Oil and Gas Incentives: EOR and Marginal Well Credits

Transcription

1 Oil and Gas Incentives: EOR and Marginal Well Credits Presented at the TEI, Houston Chapter, Tax School February 23, 2017 Houston, Texas

2 2 Presentation Outline The Marginal Well Credit Issues with natural gas wellhead prices The EOR Tax Credit High Value Methods Certifications Qualified Costs Examples Allocations Issues Bio

3 3 45I. Credit for producing oil and gas from marginal wells Credit of $3/BBL qualified oil, $0.50/MCF qualified natural gas To qualify Not more than 15BBL oil per day or 90MCF gas per day Or 25 BOEQ per day and 95% or more water production Applies to first 3 BOPD and 18 MCFPD of natural gas Application limited to 1095 BOEQ per year per well Worth up to $9 per day per well, $3,285 per year per well Credit begins to phase out when the Reference Price exceeds $15/BBL oil, $1.67/MCF gas Inflation adjusted 2015 estimate at $18.37 for oil and $2.05 for gas $3/BBL and $0.33/MCF phase out, $21.37 and $2.38 Secretary to publish Reference Price annually Oil Reference Price $44.39 in 2015 No marginal oil well credit Gas Reference Price not published

4 4 45I Reference Price for Natural Gas Average annual well head price per MCF of natural gas Published by US Energy Information Administration (US EIA) Publication of average wellhead price of natural gas stopped 12/2012 Main reason Secretary has not published an estimate Can Taxpayers make their own estimate if Secretary fails in their duty? Problems with EIA historic wellhead price for natural gas The price includes all costs prior to shipment from the lease, including gathering and compression costs, in addition to state production, severance, and similar charges Gas is often processed to meet pipeline specifications EIA price arguably not truly a wellhead price EIA posted wellhead prices likely higher than actual wellhead prices Alternative methods of determining a reference price Linear regression with other US EIA natural gas published prices 2015 estimates range from $2.64 to $2.91 Assumes EIA gas price accurately reflects well head price Actual well head price probably lower We need a source for natural gas average well head prices

5 5 The EOR Tax Credit Worth $100 s of Millions across the industry in 2016 Credit has been phased out in past years due to high oil prices 2016 first year credit will be available since 2005 Will be available in 2017 according to LTC calculations Generally impacts earnings immediately General Business Credit (section 38) subject to AMT May not immediately reduce tax, might even increase Conceptually simple but computationally complex Engineers Financial Accounting Tax (Income tax and legal) Facts and circumstances Many new companies in this space Independents MLP s

6 6 Summary of the EOR Tax Credit Section 43 of the Internal Revenue Code 15% Federal Tax Credit Loss of related deduction $100 qualified expense» Without credit, $100 deduction, $0 credit» With credit, $85 deduction, $15 credit General Business Credit subject to AMT Applies to Qualified EOR Projects Requires an operating mineral interest as defined by (b) Qualified EOR methods Original and continuing certifications First injection after Significant Expansions of pre-1991 projects qualify At this point, all projects should have significant expansions Located within the United States Applies to Qualified Tangible, IDC s and Tertiary Injectant Costs

7 7 Qualified EOR Methods ( (e)) Thermal Methods Steam Drive Cyclic Steam In Situ Combustion Gas Flood Recovery Methods Miscible Fluid Injection CO 2 Augmented Immiscible Nitrogen Immiscible Non-Hydrocarbon Gas Displacement Chemical Flood Recovery Methods Micro-Emulsion Flooding Caustic Flooding MEOR? Mobility Control Polymer Floods Must impact oil/water mobility ratios Additional methods by IRS Private Letter Ruling

8 8 Non-Qualified Methods ( (e)(3)) Water flooding Cyclic hydrocarbon gas injection Horizontal drilling Gravity Drainage Any unspecified methods These methods may qualify if they are part of a qualified project Water flooding (WAG) with horizontal CO2 injections wells Both water injection costs and well costs are qualified

9 9 EOR Project Original Certifications ( (a)) Identification of the Operator Name and Taxpayer ID of submitting party Typically submitted by field operator but can be a designated owner Statement identifying the project and its location Tertiary recovery statement Summary description of the EOR project Implemented with sound engineering practices Project employs a qualified EOR method Date of first injection Statement of more than an insignificant increase in ultimate production Reserve estimates with and without the project Production history and forecasts Reservoir delineation More information required for Significant Expansions

10 10 EOR Project Original Certifications ( (a)) Signed by Registered Professional Petroleum Engineer Statement that project is qualified under section 43(c)(2)(A) Send to Ogden Submission Processing Center, P.O. Box 9941, Ogden, UT Indications that this address will change to Houston sometime this year Due by the date federal tax return is filed (minimal sanctions) Credit not allowed until after certifications are submitted New Address and Form Internal Revenue Service LB&I Enterprise Activities Practice Area Attention: Director's Office 1919 Smith Street, Mail Stop 1003-HOU Houston, TX 77002

11 11 Significant Expansion Certifications ( (a)(3)(ii)) Required where pre-1991 injection existed into the same reservoir volume Extra documentation required to certify projects in areas with pre injection Delineation of previously affected reservoir volume Affect reservoir volume substantially unaffected by pre-1991 injection For projects where prior injection terminated for 36 months or more When prior project terminated How determined Can request a Private Letter Ruling from IRS if less than 36 months Can request a Private Letter Ruling from IRS if affecting same volume More than in insignificant increase in ultimate recovery

12 12 Continuing Certifications ( (b)) Every year following Original Certification Identification of the Operator Name and Taxpayer ID of submitting party Statement identifying the project and its location Date Original Certification was filed Statement that operations are essentially as set out in the Original Certification Statement of any deviations from Original Certification Signed by responsible party Doesn t have to be a Registered Petroleum Engineer Certifications due by the date federal tax return is filed Internal Revenue Service Center, Ogden, Utah This location is likely to change to Houston some time this year Operator may designate any other operating interest owner to file Can t claim credits until certifications have been filed No other penalties for failing to file certifications timely

13 13 Project Termination ( (c)) IRS requires notice if an EOR project is terminated Identification of the Operator Name and Taxpayer ID of submitting party Statement identifying the project and its location Date Original Certification was filed Date EOR project was terminated Not sure why filing Terminations has any usefulness Possibly if a significant expansion occurs later?

14 14 Qualified Tangible Property Costs ( (b)(3)) Costs paid for depreciable equipment that is an integral part of a qualified EOR project Used directly in the project Essential to its completeness Almost all tangibles upstream of the LACT Examples: Down-hole equipment Pumping units Steam generator Separation equipment Compressors Gas processing equipment essential to EOR operations Injectant storage tanks Financial costs associated with acquisitions of above Allocated overhead

15 15 Non-Qualifying Tangible Costs Office buildings Vehicles Oil storage tanks Oil Refinery Gas processing plant not integral to EOR operations Oil pipelines Gathering lines are ok Water disposal facilities Injection pumps Storage Pipelines

16 16 Intangible Drilling & Development Costs ( (b)(2)) All intangible drilling and development costs incurred in connection with a qualified EOR project Integral and essential Costs of drilling source wells for water, CO 2, or other qualified tertiary injectants Costs of water disposal wells in some circumstances IRS generally doesn t like these costs

17 17 Qualified Tertiary Injectant Costs ( (b)(1)) Costs paid or incurred for any tertiary injectant which is used as part of a tertiary recovery method consistent with 193(b). Expenditures related to the use as well as the acquisition of tertiary injectants (Rev. Rul ) Costs to inject, recover and re-inject purchased or recovered tertiary injectant Recycling costs Primary purpose of implementing a qualified EOR project Integral and essential to the project Injectants that typically are not considered tertiary become tertiary if part of a qualified tertiary process Water injection when part of Water Alternating Gas (WAG) in CO2 projects

18 18 Excluded From Tertiary Injectant Costs Costs that would be paid or incurred in the development and operation of a non-eor mineral property (Rev. Rul ) SERIOUSLY? Have to look to published guidance to understand what this means Industry Directives Industry Director Directive #1 on Enhanced Oil Recovery Credit 5/1/2007 Industry Directors Directive #2 on Enhanced Oil Recovery Credit 5/19/2009 Water disposal equipment and costs Plugging and abandonment costs Property and severance taxes, royalties Except with self produced injectants Well workover costs not related to tertiary injectant Disposal costs of tertiary injectant Costs without a reasonable nexus to the acquisition, production, injection, recovery, or reinjection of a tertiary injectant

19 19 Qualified Tertiary Injectant Costs Generic Industry Directive #1 Operation of equipment used to produce, recover, recycle and reinject tertiary injectant into the reservoir Operation of source wells, pumps, compressors, etc. to transport tertiary injectant from the point of acquisition to the EOR project The repair of equipment used to produce, recover, recycle and reinject tertiary injectant into the reservoir Performing workovers on injection wells Wages & benefits of field personnel engaged in qualifying activities Payments to third parties for raw materials, fuel and utilities for qualifying activities as well as costs to perform qualifying activities Overhead supporting qualifying activities that are of the magnitude that non-operators would reimburse the operator

20 20 Qualified Tertiary Injectant Costs - Examples Purchase and transportation costs for CO 2 Cost of natural gas and operating costs of steam generators for steam injection Allocated portion of gas plant used to separate and recover CO2 or Nitrogen Allocated costs of producing and recovering water used in WAG or steam operations Allocated costs of well workovers Allocated electricity costs Allocated portion of costs above field (overhead) Emphasis on Allocated Facts and circumstances Many costs generally thought of as field operating costs

21 21 Cost Allocations Many costs relate to multiple projects Require cost allocations Among qualifying projects Between qualifying and non-qualifying operations Allocation safe harbor ( (a)(2)) 90% can be rounded up to 100% Allocations can use any reasonable method Does not have to be the best or most reasonable Well counts, production or injection volumes, reserves Anticipated use is ok IRS: Allocations not allowed for tertiary injectants! Industry Directive #2, topic 5 Directives no longer used Lost but not forgotten Read on.

22 22 90% safe harbor applied to tertiary injectant Industry Directive #2, topic 5 Costs are known so no allocation needed Purchase injectant has a unit cost, recycled injectant has an average cost Injection volumes are known (measured) for each well No need to allocate a known IRS facts are wrong Costs and volumes are commingled, inherently an allocation Purchase/recycled CO2 commonly commingled prior to injection Purchased injectant often has variable pricing across a day, month or year Recycled injectant costs average numerous accounts across inj volumes Any average is an allocation Potential for substantial time and effort savings IRS requires tracking of each well in a project along with well allocations Often multiple projects for field, 100 s of wells per project Once 90% of injection is qualified, no further injection allocations

23 23 Industry Directive #2, Topic 5 IRS: Injectant purchase costs are known True, but costs change monthly or even daily, accounted for monthly or yearly Unit purchase cost is a blended cost, an allocation Purchased and recycled injectants are routinely commingled before injection What portion of injection volume at the well is purchased? Recycled? IRS: Costs of self produced or recycled injectants are known Generally dozens of cost accounts included in any computation Costs are allocated between qualifying and nonqualifying activities Unit cost determined using the sum of all allocated costs and allocated injection An average unit cost is itself an allocation IRS: Injectant volumes are know for each injection well Depending on injection volumes measurement, generally accurate Cost determinations are inherently an allocation Bottom line tertiary injectant cost determination is an allocation!

24 24 Industry Directive #2, Topic 5 IRS position is inconsistent with Holding of Rev Rul Costs that are related to the use of a tertiary injectant and that also are related to other activities (for example, primary or secondary recovery) must be reasonably allocated among the tertiary injectant and the other activities to determine the amount of tertiary injectant expenses paid or incurred by the taxpayer for the taxable year. emphasis added

25 25 Paid or Incurred ( (a)(1)) Issues Tan/IDC do not follow depreciable property rules - Costs paid or incurred in 2016 Fiscal years taxpayers Costs incurred in 2015 fiscal year but 2016 calendar year do not qualify Costs incurred in 2016 fiscal year but 2017 calendar year do qualify Missing Certifications How many companies continued issuing certifications for the last 10 years? Non-Operating working interest owners Obtaining information related to EOR projects Capital and operating costs Joint Interest Billings generally high level Production data & well list Self produced cost, not transfer prices Try to minimize number of projects Amended returns

26 26 Wrap up Marginal well credit may qualify for gas wells How to get there? EOR Tax Credit generates a valuable tax benefit Impacts earnings and cash flow Applies to Tangible costs IDC s Injectant costs Purchases Operating expenses related to recycling Some types of company overhead and interest Most common EOR methods Others by special request (PLR) Original and continuing certifications required Take advantage of allocation options

27 Jeff Lambert 27 Jeff is a petroleum engineer turned tax expert who specializes in federal income tax issues and controversies. His primary areas of concentration are dealing with IRS audits, petroleum industry, and technical tax issues. Jeff and his company, Lambert Tax Consultants, have spent thousands of hours working with IRS Agents to apply tax law in the EOR tax credit area. Clients include the biggest names in the industry as well as a number of smaller independents. Jeff and the staff at Lambert Tax Consultants have generated more than $500 million in cash tax benefit for clients from the EOR Tax Credit. Mr. Lambert has 30 years in the oil patch, most of them dealing with complex tax issues. His experience covers technical issues, particularly the EOR Tax Credit. He has worked for both the IRS and industry, applying his unique background to developing and resolving complex tax issues. He has testified as an expert witness for both industry and IRS and spoken at various tax conferences in addition to being an outside speaker at IRS training. Jeff earned his Bachelor s degree in Petroleum Engineering from New Mexico Tech, his Master s degree in Mineral Economics from Colorado School of Mines, and obtained his undergraduate accounting education at the University of Virginia. He is a registered Petroleum Engineer, CA license number P