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	Tax Provisions in 2011 Federal Budget
	Cap-And-Trade Presentation at Texas Tech University

BAMM Filing Deadline Is December 31, 2011

EDITOR’S NOTE: Last week we published a summary of EPA’s Mandatory Greenhouse Gas reporting rule Subpart W. The summary stated that operators must develop and maintain a GHG monitoring plan that outlines the methodologies and procedures for measuring, collecting and recording data. When a particular monitoring method is not feasible, operators may use the best available monitoring method (BAMM), which allows operators time to obtain monitoring equipment. Below is additional information about BAMM. The electronic Greenhouse Gas Reporting Tool (e-GGRT) is now accepting electronic Notices of Intent (NOI's) and Best Available Monitoring Methods (BAMM) submissions for Subpart W for the purposes of fulfilling requirements in 40 CFR 98.234(f). If you would like further guidance on registering for and using e-GGRT, please go to the following link: http://www.ccdsupport.com

Please note that that NOI's must be submitted electronically in e-GGRT by January 3, 2012. If you have questions regarding this communication or any additional questions you would like to pose to EPA, please visit the Help Website http://www.ccdsupport.com/confluence/display/help/Contact+Us or submit those questions to the Greenhouse Gas Reporting Program (GHGRP) Help Desk by telephone at 1-877-444-1188 or via e-mail to GHGReporting@epa.gov.

PLEASE NOTE THAT YOU MUST FIRST REGISTER A 'DESIGNATED REPRESENTATIVE' PRIOR TO FILING THE NOTICE OF INTENT (NOI)......HOWEVER, IT TAKES 7 DAYS FOR THE DESIGNATED REPRESENTATIVE FILING TO BE RECOGNIZED AND ONLY AFTER THAT WILL THE NOI BE VERIFIED AND ACCEPTED.

Operators must register with EPA a Notice of Intent to use the Best Available Monitoring Methods (BAMM) when reporting 2011 greenhouse gas emissions (GHG). This registration and Notice of Intent must be submitted by December 31, 2011.

Alliance members are encouraged to review this information and determine applicability as facilities subject to the rule are required to submit 2011 GHG emission data for their facilities on September 28, 2012.

BAMM is available to accommodate those producers and/or operations which cannot be directly measured. By applying for BAMM, the operator will receive an additional 90 day to March 31st .

EPA has allowed operators to use BAMM for 2011 for all data points and facilities subject to the rule; however, to use BAMM through June 30, 2012 and beyond, operators must submit a Notice of Intent (NOI) and Extension Request to EPA. For any data points not included in the BAMM request, companies must start collecting data according to EPA’s requirements by January 1, 2012.

Submission dates:

NOI – submitted electronically by December 31, 2011

Extension Requests - submitted electronically by March 30, 2012

The NOI submittal includes the identification of all facilities for which BAMM is needed, the types of emission sources, and the applicable BAMM provision of the rule. This will take time so don’t wait until December 31! Likewise, operators are recommended to start early on the Extension Request submittals. It should be noted that operators submitting a BAMM NOI, but do not follow up with an Extension Request are not allowed to use BAMM for 2012.

The operator must register a Designated Representative, Alternate Designated Representative or Agent using the e-GRRT (Electronic - Greenhouse Gas Reporting Tool) system on the EPA website.

What Methods Qualify as BAMM?

BAMM could include the following:

• Monitoring methods currently used by your facility that do not meet the specifications of a relevant subpart (including use of industry accepted or company used emission factors, e.g., the API Compendium)

• Supplier data

• Engineering calculations

• Other company records

Please find below the instructions for registering a new User, Agent or Designated Representative in e-GGRT. Most of your members will probably be the DR for their companies, so registering multiple users, agents or DR’s won’t be much of an issue, but in the case that a company does have multiple users, agents or DR’s they must all be registered in e-GGRT. Once you print and sign the signature page it must be mailed to the EPA. Once they approve it you can login and begin registering facilities (must have to file an NOI). Keep in mind the mail schedule around the holidays.

The steps to follow are shown below (the buttons to push have been highlighted in blue text):

Go to the main e-GGRT page https://ghgreporting.epa.gov/ghg/login.do

1. Click on the “New User Registration” button.

2. This will bring up a screen explaining the process. Click on the “Begin Registration” button

3. On the next screen, leave the radio button “I am a DR, ADR, or Agent (but not for a CAMD facility)” checked, and click on the “Continue” button

4. Check “I have reviewed and agree to the following conditions for the access and use of my account” button, and click on the “Continue” button

5. Enter your contact information and click the “Save” button

6. You will have to choose 5 challenge questions/answers on the next form – choose these and click “Save”

7. On the next screen, you will see a pdf document – that needs to be printed, signed and mailed to the address on the form – (and yes, SAIC developed the system – but not our part of the company)

Once you get an email back from EPA you will be able to access the system and finish the registration process.

The Alliance thanks Mr. Bill Bailey, EHS Specialist, Devon Energy for sharing information about Subpart W with the Alliance and you, our members. He will be one of several speakers at an Environmental Compliance Conference in Fort Worth on January 13. To register, go to www.texasalliance.org and click on “Other Meetings.”

Summary Of EPA’s Subpart W Reporting Requirements

The Environmental Protection Agency adopted the final Mandatory Greenhouse Gas (GHG) reporting rule Subpart W on November 8, 2010, and owners of onshore oil and gas production facilities must report their 2011 emissions by March 31, 2012.

Petroleum and natural gas operations that emit 25,000 tonnes per year or more of carbon dioxide (CO2) equivalent must report annual methane and CO2 emissions from equipment leaks and venting, and emissions of CO2, CH4 and nitrous oxide (N2O) from gas flaring from onshore petroleum and natural gas production stationary and portable combustion emissions, and combustion emissions from stationary equipment involved in natural gas distribution.

Operators should document production equipment by facility, which will provide the basis for estimating emissions and determining if the facility is subject to reporting requirements. For more information, go tohttp://www.epa.gov/climatechange/emissions/subpart/w.html

Engineering estimates or direct measurement of the equipment will determine the GHG assessment. If emission estimates of the facility reach the threshold of Subpart W, the operator must be able to collect, track, analyze and report emissions.

EPA has broadly defined “facility” as all production equipment as either stationary and portable but not self-propelled that is located within a single hydrogeologic basin, using AAPG Geologic Province Code maps. This definition is so broad that operators are required the lump together equipment from a network of wellsites that could stretch across several counties and even state boundaries.

EPA requires that operators keep emission data, which includes all estimated and measured data used in obtaining the GHG figures, and make it available to EPA upon request.

Operators must develop and maintain a GHG monitoring plan that outline the methodologies and procedures for measuring collecting and recording data, and includes any best-available monitoring methods (BAMM) that are used when a particular monitoring method is not feasible for the reporting facility. BAMM also allows industry time to obtain the necessary monitoring equipment and to put procedure in place to meet the monitoring requirements during 2011.

EPA website page on the Electronic Greenhouse Gas Reporting Tool: https://ghgreporting.epa.gov/ghg/login.do

CLICK HERE for Devon's GHG Applicability tool (Excel file)

SPCC Plan Basics (Power Point file) For more information on SPCC Plans, contact Alliance President Alex Mills at alexm@texasalliance.org

10 Essential Principles For Sound Energy Policy

Oil and Gas Tax Proposals Petition

Negative Economic Empact 2010 Federal Budget Proposals on Oil and Gas Extraction

RAPPS

Oil/Gas Tax Provisions In President Obama’s Proposed 2010 Budget

Intangible Drilling and Development Costs (IDC) – IDC tax treatment is designed to attract capital to the high risk business of natural gas and oil production. Expensing IDC has been part of the tax code since 1913. IDC generally include any cost incurred that has no salvage value and is necessary for the drilling of wells or the preparation of wells for the production of natural gas or oil. Only independent producers can fully expense IDC on American production. Eliminating IDC expensing would remove over $3 billion that would have been invested in new American production.

Percentage Depletion – All natural resources minerals are eligible for a percentage depletion income tax deduction. Percentage depletion for natural gas and oil has been in the tax code since 1926. Unlike percentage depletion for all other resources, natural gas and oil percentage depletion is highly limited. It is available only for American production, only available to independent producers, only available for the first 1000 barrels per day of production, limited to the net income of a property and limited to 65 percent of the producer’s net income. Percentage depletion provides capital primarily for smaller independents and is particularly important for marginal well operators. Eliminating percentage depletion would remove over $8 billion that would have been invested in maintaining and developing American production.

Geological and Geophysical (G&G) Amortization – G&G costs are associated with developing new American natural gas and oil resources. For decades, they were expensed until a tax court case concluded that they should be amortized over the life of the well. In 2005 Congress set the amortization period at two years. Later, Congress extended the amortization period to five years for large major integrated oil companies and then extended the period to seven years. Early recovery of G&G costs allows for more investment in finding new resources. Extending the amortization period would remove over $1 billion from efforts to find and develop new American production.

Marginal Well Tax Credit – This countercyclical tax credit was recommended by the National Petroleum Council in 1994 to create a safety net for marginal wells during periods of low prices. These wells – that account for 20 percent of American oil and 12 percent of American natural gas – are the most vulnerable to shutting down forever when prices fall to low levels. Enacted in 2004, the marginal well tax credit has not been needed, but it remains a key element of support for American production – and American energy security.

Enhanced Oil Recovery (EOR) Tax Credit – The EOR credit is designed to encourage oil production using costly technologies that are required after a well passes through its initial phase of production. For example, one of the technologies is the use of carbon dioxide as an injectant. Given the increased interest in carbon capture and sequestration, carbon dioxide EOR offers the potential to sequester the carbon dioxide while increasing American oil production. Currently, the oil price threshold for the EOR tax credit has been exceeded and the oil value is considered adequate to justify the EOR efforts. However, at lower prices EOR becomes uneconomic and these costly wells would be shutdown.

Manufacturing Tax Deduction – Congress enacted this provision in 2004 to encourage the development of American jobs. All US manufacturers benefitted from the deduction until 2008 when the oil and natural gas industry was restricted to a six percent deduction while other manufacturers will grow to a nine percent deduction. While many producers’ deductions are capped by the payroll limitation in the law, it is another tax provision that provides capital to America’s independent producers to invest in new production.

Excise Tax on Gulf of Mexico Production – American independent producers hold 90 percent of the OCS leases in the Gulf of Mexico. Offshore federal lands produce 27 percent of America’s oil and 15 percent of America’s natural gas. Producers pay royalties as high as 16.67 percent on their production. A portion of this production is produced without royalty payments until it reaches a set volume that was designed to encourage – and effectively so – development of deep water areas. Creating a new tax designed to add a $5 billion burden on US offshore development will drive producers from the US offshore reducing new American production of natural gas and oil.

Passive Loss Exception for Working Interests in Oil and Gas Properties – The Tax Reform Act of 1986 divided investment income/expense into two baskets – active income/loss and passive income/loss. The Act exempted working interests in oil and natural gas from being part of the passive income basket and the treatment of IDC’s, in particular, was deemed to be an active loss that could be used to offset any type of active income. If, in the future, income/loss, arising from the ownership of oil and natural gas working interests, is treated as passive income/loss, the primary reason for individuals to invest in oil and gas working interests would be significantly diminished.

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