Royalty Valuation Federal Gas Tutorials

Royalty Valuation Federal Gas Tutorials
ONLY FEDERAL – NOT INDIAN Amy Lunt ONRR Royalty Valuation Supervisor Chris Carey ONRR Royalty Valuation Petroleum Engineer

Disclaimer The statements or opinions expressed in all ONRR presentations and panel discussions at the 2019 PASO-Tulsa Federal/Indian Royalty Compliance Workshop do not necessarily represent the views of ONRR or the Department of the Interior. AMY & CHRIS Also note that we had a pretty long break from thinking about federal gas valuation during January, so might not be quite back up to where we were before the holidays. This is intended to help payors, and not necessarily be an exposition of the valuation regs. So, we are creating broad-brush strokes. The hard thing about valuation is that the guidance is very fact-dependent, and situation specific. So, don’t get all worked up if you think of an exception to something we say or our language isn’t exactly what the regs say. We will do a lot of paraphrasing to hopefully make it more understandable.

Who are we? Amy Chris Kindest, most flexible supervisor ever
Fearless leader of the Payor Handbook team Extensive rule writing (and repealing) experience 15 years at ONRR, 10 years in RV Chris Reporter letter writer extraordinaire (especially of revised ones…) Teacher, trainer, mentor, and advocate of all things valuation 11 years at ONRR, 10 years in RV BOTH Chris introduce Amy, and Amy introduce Chris

Guess who? Where is this? And, who has been here?
Use this opportunity to practice hand-raising. Who thinks this is in Florida? Who thinks this is in Alaska? Good job! See, it’s not that hard to lift your hand  Now, try again, who thinks Amy has been here? Who thinks Chris?

Wrangell-St. Elias National Park
Guess who? Mount Baldy Wrangell-St. Elias National Park & Preserve Circa a long time ago

Guess where? Paluma Range National Park Queensland, Australia
Does anyone know where this is? How about now? Can you match the kid with the parent? Paluma Range National Park Queensland, Australia Billabong Wildlife Sanctuary Queensland, Australia

Guess who? … raises chickens
Who thinks Amy raises chickens? Who thinks Chris?

To keep you out of hot water!
Why are we here? To keep you out of hot water! AMY Our goal when responding to industry is to keep you safe in an audit. That means you’ll get the most conservative answer and one that is consistent and supported by the regulations and case law where applicable. We are not in the practice of referring you to audit if you contact us. Now, if we see something egregious AND no intention to fix it, then we may need to refer you. But, we see you looking to get things right, you are in a safe place.

Who is Royalty Valuation?
Royalty Valuation Manager – John Barder RV Team A (Amy Lunt) Chris Carey Helen Virene Cindy Gothberg Kim Jackson Vacant RV Team B (Peter Christnacht) Megan Hessee Rob Malandri Herb Black Gina Liles Jodie Peterson RV Team C (Karl Wunderlich) Sara Corman Yasmen Faied Meghan Trujillo Allison Forrest Noelle White AMY Ask John Barder to stand Special thanks to Chris Carey for developing this presentation Special thanks to Kim for herding the PASO cats Ask for patience as we bring n

RV What does RV do? Generate UCAs Payor handbooks Guidance
Determinations Requests to exceed allowance limits Maintain database of valuation policy and guidance Support compliance activities Brief issues and policy Support OIG / DOJ Cross-training RPC support Write regulations Reporter letters Payor training Internal training Payor handbooks Generate UCAs Review industry unbundling methods AMY Guidance Determinations Requests to Exceed Allowance limits Maintain database of valuation policy and guidance Support STRAC and ONRR compliance activities – Houston PD call and MT consulting Brief issues and develop policy through the CSC Support OIG / DOJ Cross-train ONRR and STRAC employees Support RPC Write Regulations Reporter Letters - The revised keepwhole letter just went out and we are working on a POP reporter letter Payor Training – Look for webex-style training this year! ONRR/STRAC Training Re-write the Payor Handbook Generate UCAs - we just published new standardized UCAs for San Juan and Green River basins Review industry unbundling methods

Outline Key valuation concepts (20 min)
Arm’s length vs non-arm’s length Arm’s-length sales points Marketable condition Very helpful things to understand (20 min) Fuel & condensate Royalty reporting: marketable condition costs for unprocessed vs processed gas Unbundling expectations Example scenarios (20 min) For your curiosity (15 min) AMY We’re going to start with the basics and then address some specific situations. Remember, we’re only talking about Federal gas. If you do the math with these time segments, you’ll notice they don’t quite reach 1 hr and 40 min. We have a fun surprise stored up to help recap some of what we will present. Stay tuned and don’t fall asleep!

A few quick comments To save space on slides, we sometimes abbreviate:
MC = Marketable Condition AL = Arm’s Length NAL = Non-Arm’s Length What gross proceeds means: “monies and other consideration.” MC services are considered other consideration. Gross proceeds is your total value for royalty purposes (in most arm’s-length situations) AMY

Gross Proceeds Gross proceeds means the total monies and other consideration accruing to an oil and gas lessee for the disposition of production. You produce 25 MMBtu of gas from Federal land that is adjacent to your back yard and sell it to your neighbor at arm’s length for: $20 5 chickens 1 goat Let’s review what gross proceeds means. It is the total monies and other consideration accruing to the lessee. Basically, “everything you get in return for selling your gas to someone” If asked, some taxes are not allowed: Tax reimbursements Severance taxes And some are allowed: NM gas processors tax Let’s illustrate this principle with an example: Lets say that you live in rural Oklahoma and lease some Federal land that is adjacent to your backyard. Your neighbor needs some natural gas, and you have a bit of a homestead, so you negotiate to sell your neighbor 25 MMBtu of gas and he gives you $20, one goat, and five chickens in exchange. Now you are stuck having to pay royalties to ONRR. What are your gross proceeds for royalty purposes? Get ready! Regs: 30 CFR § 13

Question! $20 $20 and the market value of the 5 chickens and 1 goat
What are your gross proceeds (“total monies and other consideration”)? $20 $20 and the market value of the 5 chickens and 1 goat Comparable arm’s-length sales Everyone select the answer that you believe is correct. The correct answer is B. So, why not A? Because the goat and chickens represent additional consideration. And why not C? Because the sale was arm’s-length. You might use comparable arm’s- length sales in a non-arm’s-length scenario, but not here. Highlight the analogy. The goats and chickens represent marketable condition services performed by the purchaser. The value of those services is part of your gross proceeds! 14

Arm’s Length vs Non-Arm’s Length
Key Concepts AMY There are three primary considerations when valuing Federal gas. They are: Does the sale occur at arm’s-length or not? Where is the sales point? And, when does the gas reach marketable condition, and has the lessee been careful to not deduct any disallowed costs? Arm’s Length vs Non-Arm’s Length Sales Point Marketable Condition

Arm’s-Length Contracts
What is an arm’s-length contract? Why does it matter? How can you figure out whether your contract is arm’s length? Common pitfalls AMY For each of the three main concepts, we will highlight the following [read list of 4 things] More than any other concept, the relationship between parties to a contract underpins the way we view that contract as a viable option for royalty valuation. This holds true for valuation of most commodities, including real estate, cars, coal, and as Peter discussed, oil. For most things, the best indicator of value is the price established in a contract between to unrelated parties acting with opposing economic interests. In terms of ONRR’s regulations, having an arm’s-length contract makes your reporting and valuation easier. But first, let’s define an arm’s-length contract.

Arm’s Length or Non-Arm’s Length?
Are the parties… Affiliated? Does the entity control, is it controlled by, or is it under common control with another entity? Negotiated with opposing economic interests? Related by blood or marriage? 0% 10% 50% 100% Degree of Control Non-arm’s-length Consider additional factors Arm’s-length AMY The test for arm’s-length vs non-arm’s-length is based on 1. affiliation (as defined in detail in the regulations) and opposing economic interests (which is not defined in the regulations). For affiliation: If there is more than 50% ownership, we assume the relationship to be non-arm’s length and it is in blue If it is less than 10%, we assume it to be arm’s length and will be colored green If it is between 10 and 50%, then additional factors need to be considered. The regulations outline these additional factors, which include things like: 1) common officers or board of directors 2) percentage ownership and voting securities 3) the owners participation in operations 4) other evidence of control For a contract to be arm’s-length, the parties must not be affiliated AND they must act with opposing economic interests. The regs do not spell out what that means, but the Vastar Resources IBLA case provides a very good discussion on examining elements to determine opposing economic interests. The factors the IBLA outlined in Vastar include: negotiating the contract – were negotiations protracted and difficult? the specific provisions of the contract – does the contract itself evidence fair market practices? does the contract include index pricing? Also, for a contract to be arm’s-length, the parties must not be affiliated and must have opposing economic interests both when the contract is executed and for that production month. So, why does it matter whether we distinguish between arm’s-length and non-arm’s-length relationships? Because non-arm’s-length agreements may not reflect true market value, which is what we want to base royalty on. Regs: 30 CFR § 17

Why does it matter?  Different valuation methods: Arm’s-length sales are valued based on gross proceeds Non-arm’s-length sales are valued under a series of benchmarks Processed gas vs unprocessed gas regulations How can you find out?  Often, this is an easy call. If not, you should examine two aspects: Affiliation Opposing economic interests AMY Concept of toolbox – documents you need and who you should talk to Talk about 152 and 153 This is a great time to Regs: 30 CFR §§ , ,

Common pitfalls: Assuming that the sale is arm’s length Assuming that the sale is non-arm’s length Applying the non-arm’s-length benchmarks out of order Confusing the nature of the sales contract with the nature of the transportation or processing contract AMY

Arm’s-Length Sales Point
Where does title, custody, and control of the gas permanently transfer to the purchaser? Here? Here? Here? Federal Lease Chris! What is the sales point? This isn’t defined in the regs, per se, but it is a necessary outgrowth needed to determine whether or not the gas is sold before or after processing. So, we consider the sales point to be the location where title, custody, and control of the gas permanently transfer to the purchaser.

Why does it matter? If the arm’s-length sales point is before processing, the gas is valued as unprocessed gas If the arm’s-length sales point is after processing, the gas is valued as processed gas CHRIS Why does it matter? Because it determines whether gas is valued and reported as processed or unprocessed.

Question! For non-arm’s-length gas sales, does the sales point dictate whether or not it is valued as unprocessed or processed gas? Yes No CHRIS The correct answer is “NO.” Let’s look at why in the next two slides…

Gas Valuation Decision Tree Gas Can you really have a non-arm’s-length sale valued as unprocessed gas? Processed Unprocessed Arm’s Length Non-Arm’s Length Arm’s Length Non-Arm’s Length CHRIS So, for gas, the first things we think about are: Is the gas sold before or after is has been processed? Or is the gas ever processed? Is the sale arm’s or non-arm’s-length? The we determine the gross proceeds for the sale. And then see if there are any allowable deductions for transportation or processing costs. Ask Amy the question Gross Proceeds Deductions Benchmarks Deductions Gross Proceeds Deductions Benchmarks Deductions

Unprocessed Gas vs Processed Gas Which one applies? 30 CFR § – Unprocessed Gas 30 CFR § – Processed Gas All gas that is never processed All gas that is processed, but is sold at arm’s length prior to processing – including POP contracts The unprocessed gas portion of Federal dual accounting All gas that is processed by the lessee and Any other gas production that is not subject to § When the lessee’s contract includes the right to process and they exercise that right CHRIS Walk through , then note how basically catches everything else. Including gas sold NAL before processing.

Unprocessed Gas vs Processed Gas Unprocessed gas – reporting and valuing only one commodity (exceptions apply – think POP contracts) and reporting one product code: Unprocessed gas (PC 04) Coalbed methane (PC 39) Processed gas – reporting and valuing multiple commodities and reporting multiple product codes: Drip condensate (PC 05) Pipeline fuel (PC 15) Residue gas (PC 03) NGLs (PC 07) Possibly others (plant scrubber, CO2, sulfur, etc.) CHRIS Note how with POP contracts, as we will see, everything in the processed gas realm basically gets rolled up into one line. Regs: 30 CFR §§ ,

How can you find out where the sales point is? Talk to your marketing team Look in the gas sales contract Common pitfalls: The delivery point is not always the sales point The title, custody, and control did not permanently transfer The royalty measurement point is not always the sales point Chris!

Marketable Condition Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area. Gas Separation Gathering Compression Dehydration Sweetening Amy Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area. The marketable condition requirements are determined primarily by your sales contract, but we look to see whether those requirements are common for the field or area. This includes initial separation for oil and for gas. For oil, this is also includes BS&W (redefine) limits, which is usually required to be at or below 1%. For gas, this is often determined by the specifications of the main gas sales pipeline at the tailgate of a gas processing plant, though it can be elsewhere. The specifications to consider are: Pressure (compression) Water content (dehydration) Carbon dioxide (sweetening) Hydrogen sulfide (sweetening) For gathering, ONRR defines this differently than does industry. ONRR defines gathering generally as the movement of production prior to a CAP. We will talk more about this later. Be prepared to talk about why boosting is never allowed, in case it comes up here. Refer to Regs: 30 CFR §§ , , 27

Question! Separation, compression, dehydration, and sweetening are always for placing the gas in marketable condition and the costs associated with them may never be deducted from the royalty value. True False AMY The correct answer is FALSE. When the services are above and beyond what is required for placing the gas into MC, then the lessee may deduct the costs of these services.

Marketable Condition Must place the production into marketable condition at no cost to the Federal government Cannot reduce royalties by transferring the costs to the purchaser for a lower sales value Gross proceeds should be increased to the extent they were reduced for costs associated with placing the production into marketable condition If the lessee meets or exceeds the marketable condition requirements, they may be able to deduct a portion of their costs AMY Go through the slide These are some of the core principles of marketable condition. The definition of marketable condition has not changed We’ll walk through some examples later under the gas valuation section. Regs: 30 CFR §§ , , 29

This is a great time to email ONRRUnbundling@onrr.gov!
Marketable Condition Why does it matter?  You are likely underpaying royalties if you pass marketable condition costs on to the taxpayer. How can you find out whether you’re reporting and paying correctly? Do your research What is the condition of your gas at the wellhead? What is marketable condition for that area? Where is the gas compressed, dehydrated, treated, etc.? Talk to your engineers, marketers, service providers, and purchasers AMY Deducting MC costs is the most common liability for underpaid royalties. The burden lies on you, the lessee to make sure you are not reducing royalties for MC-related costs. This is a great time to

Marketable Condition Common pitfalls:
Assuming that if the gas is sold, it must be in marketable condition It’s too complicated, so I’m just going to ignore it Taking a partial deduction, with no reasoned basis – “50/50 seems fair!” AMY Don’t ignore it!

Other Important Things to know
Fuel & Condensate Royalty Reporting: Marketable Condition Unbundling Expectations

Gas Used for Fuel Beneficial Use Pipeline Fuel Plant Fuel
Federal Lease Gas Well Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Chris We receive a lot of questions about fuel use. When we examine fuel use – it is easiest to break it up into three categories, which we look examine in greater detail on the next few slides. Beneficial use is gas used on the same lease/agreement from which is was produced, and is usually used before the gas has been measured for royalty Pipeline is gas used after it has left the lease, but before it enters a gas processing plant Plant fuel is gas used in a gas processing plant Beneficial Use Pipeline Fuel Plant Fuel

Fuel – Beneficial Use Federal Lease Gas Well BLM or BSEE-Approved Royalty Measurement Point Royalty-free use usually granted under the lease terms Overseen by BLM (onshore leases) & BSEE (offshore leases) Produced gas commonly used for lease operations including power generation, heating, equipment fuel, and in instrumentation Reported on the Form ONRR Oil and Gas Operations Report Part B (OGOR-B) Not reported on the Form ONRR unless royalty bearing as required by lease terms or BLM/BSEE Chris Beneficial use is royalty-free under the terms of the lease and possibly other approvals or agreements with the BLM or BSEE. Produced gas can usually be used to generate electricity, for instrumentation, or in other equipment such as heated separators, compressors, dehydrators, etc. In some instances, the gas is too rich or contains too many acid gases to be used on the lease, so it is processed and then returned to the lease. This requires specific approval from the BLM or BSEE – you should work with them to approve the operations and make a determination regarding whether or not the gas is royalty-bearing. The volume you used on the lease should be reported separately on the OGOR- B report – see Production Reporting Handbook for instructions Because it is deemed royalty-free and not included in the royalty-bearing volumes reported on the OGOR-B, you should not report it on the Form ONRR If for some reason you are required to pay royalty on gas used on your lease or agreement, then you should report it on the 2014 and pay royalties. Regs: 30 CFR § (b)(1) 34

Fuel – Pipeline Fuel Not “royalty-free,” but certain costs allowed as part of the transportation allowance See December 18, Reporter Letter Royalty-bearing gas is often used to power compressors or other equipment along gas transportation systems Volume and value reported on the Form ONRR-2014 using PC 15 Not reported on the OGOR-B Federal Lease Compressor Station Gas Processing Plant CHRIS Our regulations do not provide for any “royalty-free” use of Federal gas along a transportation system. However, they do provide for fuel costs to be included in the transportation allowance when the fuel compresses, dehydrates, or otherwise treats the gas beyond the marketable condition requirements. Pipeline fuel is discussed in detail in the reporter letter dated December 18, In short, the full volume and value of the fuel used should be reported on the using PC 15. Then, you may include the value of the allowable fuel in your transportation allowance. There are no unique reporting requirements on the OGOR-B report. Regs: 30 CFR § (f)(9) 35

Fuel – Plant Fuel The regulations allow a reasonable amount of residue gas to be used royalty-free to operate a gas processing plant Allowable fuel may be omitted from the residue gas volume on the Form ONRR-2014 Disallowed (royalty-bearing) plant fuel should be added back to the residue gas volume and value Not reported on the OGOR-B Gas Processing Plant CHRIS Lastly, the regulations do provide for residue gas to be used royalty-free in a gas processing plant. Because it is royalty-free, you do not need to report the volume and value of the allowable fuel on the Let’s look at the brief guidance also explained in the December 18, 2014 reporter letter and use an example to further explain plant fuel… Regs: 30 CFR § (b) 36

Question If the arm’s-length sales point is immediately after the royalty measurement point, you never have to consider what happens to any condensate that may be recovered downstream for royalty purposes. True False Federal Lease Condensate? Sales Point BLM or BSEE-Approved Royalty Measurement Point

This is a great time to email RoyaltyValuation@onrr.gov!
Condensate When valuing processed gas, drip or scrubber condensate should be reported and royalties paid When valuing unprocessed gas, it depends… What does the contract say? Is the lessee paid for condensate? Is it retained in lieu of other fees? Is it mentioned at all? What is happening in the field? CHRIS The regs for processed gas provide that when paying on processed gas, royalties are due on any drip condensate recovered downstream of the RMP and before processing. The language is clear, and doesn’t provide exceptions. This is a great time to

Royalty Reporting: Marketable Condition Costs
Unprocessed gas reporting and valuation mechanism (think POP contracts) Start with what you got paid, and add back everything disallowed for placing gas into marketable condition Processed gas reporting and valuation mechanism Report 100% of the value, then deduct any allowed costs as allowances Chris Walk through the slide Regs: 30 CFR §§ and

Unprocessed Gas Regs: 30 CFR § Disallowed Sweetening The purchaser performed these services to put the gas into marketable condition. You must add back the value of these services. Disallowed Dehydration Full value of the gas for royalty purposes Disallowed Compression The gas sold just after the royalty meter was already conditioned, to an extent – gathered and separated. But it was not fully in marketable condition. What you were paid CHRIS Walk through the slide Disclaimer: This graphic and explanation combine valuation and reporting concepts. It is intended to be a helpful tool when valuing and reporting most unprocessed gas scenarios, but there will be some exceptions based on unique fact patterns.

Regs: 30 CFR § Processed Gas Allowances – Transportation and Processing Value of all Royalty-Bearing Products (residue gas, NGLs, fuel, condensate, etc.) This is the full value of your gas in MC, at the inlet of the mainline pipeline. In addition to disallowed services for placing the gas into MC, it also includes allowable services of transportation and processing. Royalty value of the gas after allowances. CHRIS Walk through the slide

Value of all Royalty-Bearing Products (residue gas, NGLs, fuel, condensate, etc.) Allowances – Transportation and Processing Disallowed Sweetening Disallowed Dehydration Processed Unprocessed = Disallowed Compression What you were paid CHRIS Walk through the slide Why did I write “POP-type?” Explain this We may need to reiterate any number of times that a POP-type contract might be a POI, or other, not necessarily an APOP – I can see people getting confused by that maybe. Under a POP-type contract, the ultimate value on which royalty is paid is the same, whether it is valued as unprocessed or processed gas. This may not be true in situations with a wellhead sale at a per-MMBtu price.

Key point – the ultimate value is the same, but the valuation and reporting mechanisms are different. Well then, why can’t we just report and value them the same way? Because the regulations don’t allow and the 2016 rule was repealed! CHRIS

Unbundling Expectations
The burden lies on the lessee to determine which costs are allowed and which costs are not What does that mean? Unbundle the costs on your own Use an ONRR UCA if available Don’t take any allowances/add back all costs AMY Mostly remind them of everything Karl already said…

Scenarios The focus: What we’ll discuss: Sales point
Nature of sale (AL vs NAL) Terms of sale Marketable condition (MC) considerations What we’ll discuss: Valuation mechanism Basic reporting How to incorporate marketable condition costs AMY The purpose of these scenarios is not to provide in-depth examples. If you want that, tune in to one of our payor training sessions. The purpose is to help you build a framework to better understand Federal gas valuation, so that you aren’t just trying to plug in a number, but actually have a sense for whether it is right or not. To that end, we will walk through seven scenarios, focusing on the following, and then discussing what the basic valuation and reporting looks like. [walk through the slide]

#1: Arm’s-Length Wellhead Sale, per-MMBtu Price
Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Arm’s length, unprocessed gas (PC 04) Sales Information: Arm’s length 80% of posted gas price MC considerations? What is MC for this gas? Is the gas in MC at the sales point? Does the purchaser further compress, dehydrate, or treat the gas? AMY Slowly walk through slide. Make sure to note: The gas could be in MC at the sales point, but we don’t know. It is important to figure that out. Just b/c the value is 80% of a posted price doesn’t mean it isn’t fair value. It could be perfectly acceptable, but not if the gas is not yet in marketable condition.

#1: Arm’s-Length Wellhead Sale, per-MMBtu Price
Key points: Report PC 04 – unprocessed gas Valuation mechanism  start with what you got paid, and add back disallowed costs. This equals your total gross proceeds. Depending on the marketable condition for your gas, you may need to add back the value of any services performed by the purchaser to place the gas into marketable condition Common mistakes: Assuming the gas is in marketable condition and not adding back any costs AMY [walk through the slide] The most conservative approach would be to pay on 100% of the posted price, though you would likely be paying more than you are required to.

#2: Non-Arm’s-Length Wellhead Sale, per-MMBtu Price
Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Sales Information: Non-arm’s length 85% of posted price Purchaser processes the gas, sells products at arm’s length at plant tailgate Valuation mechanism? Processed gas (PC 03, 07) Use benchmarks to determine value Allowances are based on actual costs Do not deduct any costs associated with placing the gas into MC AMY Things to talk through: b/c arm’s-length sale at plant tailgate, no DA required Allowance will depend on who owns the pipeline and plant – is it the affiliated purchaser or a third party?

#2: Non-Arm’s-Length Wellhead Sale, per-MMBtu Price
Key points: The first disposition of the gas is non-arm’s length Therefore the gas is valued and reported as processed gas under § Common mistakes: Going directly to the tailgate sales Reporting and valuing the gas as unprocessed AMY [talk through this slide]

#3: Arm’s-Length Wellhead Sale, POP Contract
For ONRR, a POP contract is a contract: For the sale of gas, prior to processing Value is based on a percentage of the purchaser’s proceeds resulting from processing Here Gas sold – title transferred here Gas producing lease NGLs to Sale Residue Gas to Sale Condensate to Sale CHRIS Let’s first talk about what a POP contract is, according to ONRR, and what it is not. Value is determined Regs: 30 CFR § (b)(1)(i)

Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Arm’s length, unprocessed gas (PC 04) Minimum value requirement Sales Information: Arm’s length 80% of purchaser’s proceeds CHRIS Discuss POP variations, including: 100% POPs Percent of Index (POI) MC considerations? What is MC for this gas? Is the gas in MC at the sales point? Does the purchaser further compress, dehydrate, or treat the gas?

Key points: Report PC 04 – unprocessed gas Valuation mechanism  start with what you got paid and add back disallowed costs. This equals your gross proceeds. Depending on the marketable condition for your gas, you may need to add back the value of any services performed by the purchaser to place the gas into marketable condition Compare your gross proceeds to value of 100% of the residue gas Common mistakes: Only paying royalty based on what you were paid Not comparing to the minimum value of 100% of the value of the residue gas CHRIS

Tangent: Marketable Condition Costs in POP Contracts
1 2 3 4 CHRIS I know this is super small, so I’ll go through it in four parts.

1 CHRIS Marketable condition costs can be in the value of field fuel that was used in equipment (compressors, dehydrators, etc) that placed the gas into marketable condition. You will need to value the disallowed fuel MMBtu and add that back to your gross proceeds.

2 CHRIS Here is the NGL settlement information, condensed to fit the slide. A portion of the percentage kept by the plant/purchaser could cover marketable condition-related costs.

3 CHRIS Here is the residue settlement information. Some of the plant fuel could be for placing the gas into marketable condition or for boosting. Like the pipeline fuel, the value of the disallowed portion should be added back. And similar to the NGLs, a portion of the 15% of the value of the residue gas kept by the plant/purchaser may cover costs associated with placing the gas into marketable condition.

4 Gathering Dehydration Compression Treating CHRIS And lastly, the fee section of a statement. Some of these fees may be disallowed in whole or in part.

#4: Arm’s-Length Processed Gas Sale, Fixed-Fee Processing
Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Arm’s length, processed gas (PC 03,07) Information: Arm’s length Bundled, fixed fee for transportation and processing MC considerations? What is MC for this gas? Is the gas in MC at the lease point? How much of the bundled fee was for placing the gas into MC? CHRIS Key points – pay on full value and then take allowances for allowed costs.

Key points: Report processed gas – PC 03, 07, and possibly 05, 06, and/or 15 Report and pay on 100% of the volume and value of each product, then deduct allowable costs as allowances Any costs associated with placing the gas into MC may not be included in the allowances Common mistakes: Deducting disallowed costs (didn’t unbundle) CHRIS

Variation – what if the fixed fee is unbundled? Probably Allowed Maybe partially allowed Probably Allowed CHRIS I’m sure my wishy-washy descriptions of what is allowed and what is not probably got your attention. The idea here is that we don’t know very much from the statement alone. I have seen a charge labelled as “gathering” that included compression, dehy, and NGL extraction. We need more information from the contract and/or the service provider to know whether or not some of these are allowed, and to what extent. Let’s talk through each one… Likely Mostly Disallowed Most Certainly Disallowed

#5: Arm’s-Length Processed Gas Sale, Processing % Retained
Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Arm’s length, processed gas (PC 03,07) Information: Arm’s length Processing and transportation paid with 15% of residue and 15% of NGLs MC considerations? What is MC for this gas? Is the gas in MC at the lease point? How much of the bundled fee was for placing the gas into MC? CHRIS Explain the difference between a percentage retainage, and a POP-type contract – really just the sales point!

#5: Arm’s-Length Processed Gas Sale, Processing % Retained
Key points: Report processed gas – PC 03, 07, and possibly 05, 06, and/or 15 Report and pay on 100%, then deduct allowable costs as allowances. The total costs in this example is the value of the 15% of residue and 15% of NGLs retained by the plant. Any costs associated with placing the gas into MC may not be included in the allowances Common mistakes: Not paying on 100% Deducting disallowed costs (didn’t unbundle)

#6: Arm’s-Length Processed Gas Sale, Keepwhole Processing
NGLs Residue gas All residue gas For example, gas producer delivers at plant inlet: 1,000 MMBtu 1.32 MMBtu/Mcf Composed of: 80 % Methane 8 % Ethane 7 % Propane 5 % Butanes + For example, gas producer receives at plant tailgate: 1,000 MMBtu 1.08 MMBtu/Mcf Composed of 92 % Methane 7 % Ethane 1 % Propane + CHRIS Before we talk about how to report and value a keepwhole contract, let’s first talk about what it is… Here’s a way to show it conceptually: Under a keepwhole contact, you receive the same MMBtus after processing as you delivered to the gas plant. Sometimes the plant keeps a portion of fuel, and if they do, we still consider it a keepwhole. The circles here represent the total MMBtus delivered and received back. In the first circle, the red wedge represents the MMBtus associated with the NGLs. In the second circle, the circle is still whole, but it is all residue gas. Because of this, the Btu content of the inlet gas stream will be higher than the residue, just like in any processed gas situation. So, while the MMBtus will be equal, you will actually have more Mcfs after processing. Also associated with the Btu content – if you were to examine the composition of the inlet gas stream vs the tailgate stream, you would notice that it is primarily methane and some ethane. The NGLs were stripped out. So in a keepwhole, the plant keeps your NGLs and gives you extra residue gas instead. So that’s what a keepwhole contract is. Now, how do we value it for Federal royalty purposes? Pull out your clickers!

Valued and reported as processed gas Volume: Calculate the volume of NGLs recovered by the plant Calculate the residue gas volume See August 21, 2018 Reporter Letter Value: The residue gas is valued under the processed gas regulations – AL or NAL as applicable The NGLs are valued under the 2nd benchmark for NAL processed gas Now, reporting and valuing gas processed under a keepwhole contract can be a little burdensome, because you often may not know the volume and value of the NGLs retained by the gas plant. Still, the burden lies on you, the lessee, to calculate the theoretical volume and value of NGLs, and pay on that. The November 12, 2012 reporter letter provides guidance on how to do this. For the value, The residue gas is valued under the arm’s-length or non-arm’s-length processed gas regulations as applicable. The NGLs are considered “not sold under an arm’s-length contract” and are valued under the 2nd benchmark.

Question! I knew ONRR published a fantastic revised keepwhole reporter letter last August! True False

Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Arm’s length, processed gas (PC 03,07) Information: Arm’s length Processing is under a keepwhole provision MC considerations? What is MC for this gas? Is the gas in MC at the lease point? How much of the bundled fee was for placing the gas into MC? CHRIS You still have to pay attention to MC…

Key points: Report processed gas – PC 03, 07, and possibly 05, 06, and/or 15 Properly calculate all volumes and values Any costs associated with placing the gas into MC may not be included in the allowances Common mistakes: Paying on unprocessed gas Incorrectly calculating the processed gas volumes and values Deducting disallowed costs (didn’t unbundle)

#7: Non-Arm’s-Length Processed Gas Sale
Federal Lease Compressor Station Gas Processing Plant BLM or BSEE-Approved Royalty Measurement Point Sales Point Valuation mechanism? Non-arm’s length, processed gas (PC 03,07) Information: Non-arm’s length MC considerations? What is MC for this gas? Is the gas in MC at the lease point? How much of the bundled fee was for placing the gas into MC? CHRIS

#7: Non-Arm’s-Length Processed Gas Sale
Key points: Report processed gas – PC 03, 07, and possibly 05, 06, and/or 15 Value determined under the NAL benchmarks The processing allowance must be based on depreciation, operating, maintenance, and overhead costs Any costs associated with placing the gas into MC may not be included in the allowances Common mistakes: Treating processing as arm’s length Misapplying the NAL benchmarks for the value Trying to use the NAL benchmarks for allowances Deducting disallowed costs (didn’t unbundle) CHRIS [go through slide and elaborate as needed]

For your curiosity AMY

Reporting Royalties on Liquefied Natural Gas (LNG)
Usually reported as PC 03, in MMBtu and Mcf Eligible for transportation allowances To be determined: Can liquefaction costs be deducted? If so, how? What is marketable condition for LNG? AMY [go through slide]

In-field NGL Extraction (JT Skids, MRUs, etc)
Small units that recover NGLs from one or several leases Technology usually qualifies as “processing” under ONRR rules Refrigeration J-T valve cooling Common in the Bakken because of flaring rules Be aware that the sales point can have unexpected consequences (POP contracts) AMY Explain what these units do and why they are used [go through slide]

In-field NGL Extraction (JT Skids, MRUs, etc)
Challenges: Guidance is contract specific and design specific Poor measurement of NGLs Usually short term Service contracts become sales contracts BLM approval backlog AMY Key point here – lots of challenges on various fronts This is a great time to

Non-Arm’s-length Transportation
Rise in NAL transportation allowance activity NAL allowances include: Depreciation Operating Maintenance Overhead AMY NAL transportation allowances are laid out in the regs, but are more complicated than AL allowances. With the industry downturn a few years ago see saw a strong uptick in NAL allowances, presumably in an effort to get back any money possible. A NAL allowance is made up of the following: Depreciation Operating Maintenance Overhead

Depreciation Guidelines
Is for transportation pipelines only Has slightly different rules for oil vs gas Begins when the asset is placed in service Depreciation AMY We have had a lot of questions around various options and methods for calculating depreciation. In an effort to start you off in the right direction, here are some high level guidelines. [go through each item and elaborate as needed] Must be supported with appropriate documentation Must be based on actual costs – not estimates This is a great time to

Questions Anytime ? AMY 76

COMPETITION TIME!! We Need 3 Teams of 3-5 People
One Industry Team One ONRR/STRAC Team One Team of Industry Consultants We will award prizes (not purchased with federal funds) to the team with the most correct answers!

Question 1 What temperature and pressure must you use for federal gas reporting under 30 CFR § ? 14.65 psi and 60 degrees F 14.65 psi and 65 degrees F 14.73 psi and 60 degrees F 14.73 psi and 65 degrees F The answer is C!

Question 2 You are in possession of a gas plant statement entitled “Percentage of Proceeds Statement,” listing volumes and prices for a given month. What do you know? You know that your gas is in marketable condition because someone bought it. You know your gas is processed, so you should report and pay under the processed gas regulations using PCs 05, 15, 03, & 07. You know you have a POP contract, so you should report and pay under the POP contract rules – PC 04 and no less than the value of 100% of the residue. You know that you are in real danger of misreporting and had better get your hands on the contract that goes with the statement. C again!

Question 3 The company that purchases your gas at arm’s length at the wellhead pays you 85% of the proceeds they received for your residue gas and 85% of OPIS for your NGLs. What do you know? You know the total amount that’s on your check stub and the volume so you’re good to go. You know that the 15% the purchaser keeps is for processing, so you don’t need to worry about it. You know that you need to unbundle, add back disallowed costs, and then compare your gross proceeds to 100% of the value of the residue gas. You know that you can report and pay using the numbers on the statement and not get in trouble.

Question 4 You are selling gas above market value to a non-affiliated entity with opposing economic interests under a contract negotiated between two long extinct companies in What do you know? That you are one tough negotiator. Time for a cold one! That you are not affiliated and that the purchaser is paying what the gas is worth, so it’s an arm’s-length transaction. That you can barely read the courier font from 1984, but you’d better do some research before you report using the arm’s-length valuation rules. That it’s easier to value royalties under the arm’s-length rules, so you should follow your gut.

Question 5 Name the statute! “(C) cash bonus bid, or work commitment bid based on a dollar amount for exploration with a fixed cash bonus, and a diminishing or sliding royalty based on such formulae as the Secretary shall determine as equitable to encourage continued production from the lease area as resources diminish, but not less than 12½ per centum at the beginning of the lease period in amount or value of the production saved, removed, or sold;” Mineral Leasing Act Federal Oil and Gas Royalty Management Act Royalty Simplification and Fairness Act Outer Continental Shelf Lands Act

Royalty Valuation Federal Gas Tutorials

Similar presentations

Presentation on theme: "Royalty Valuation Federal Gas Tutorials"— Presentation transcript:

Similar presentations

About project

Feedback

Log in

Auth with social network:

Royalty Valuation Federal Gas Tutorials

Similar presentations

Presentation on theme: "Royalty Valuation Federal Gas Tutorials"— Presentation transcript:

Similar presentations

About project

Feedback