Update of Onshore Orders 3, 4, and 5 Richard Estabrook, BLM Washington Office (Ukiah, CA) Petroleum Accountant’s Society of Oklahoma February 12, 2015

Update of Onshore Orders 3, 4, and 5 Richard Estabrook, BLM Washington Office (Ukiah, CA) Petroleum Accountants Society of Oklahoma February 12, 2015

DISCLAIMER These are draft proposed revisions; The BLM is not soliciting comments today; The BLM discourages you from paying attention to this presentation

Outline Overview of BLM jurisdiction, responsibility, and statistics Current measurement regulations Draft proposed changes Status and timeframes

BLM Jurisdiction and Responsibility (oil and gas) 245 million acres of public land (BLM) 325 million acres of other federal land 60 million acres of Indian trust land 57 million acres of split estate 700 million acres

BLM oil and gas responsibility: Leasing Permitting Inspection and Enforcement Drilling, plugging Environmental Proper measurement

Federal Onshore Oil and Gas Statistics (FY2013) 23,000 producing leases 12.6 million acres of producing leases 93,000 wells 135 million bbls/year of oil 2.6 trillion cubic feet of gas per year $3 billion in Federal royalty per year

Federal Onshore Measurement Regulations 43 CFR Part 3160 3162.7-2 Oil Measurement 3162.7-3 Gas Measurement 3162.7-1 Disposition of Production Onshore Order 3 Site Security Onshore Order 4 Oil Measurement Onshore Order 5 Gas Measurement Statewide NTLs EFCs Federal Oil and Gas Royalty Management Act NTL-4A Venting, flaring, bene. use, loss

Onshore Order 3 Site Security Seals (tanks and LACTS) Run tickets No meter bypasses Reporting of theft Self inspection Seal records: 6-year retention Site security plan Site facility diagram Federal seals

Onshore Order 4 Oil Measurement Tank gauging procedures Tank sampling procedures LACT, positive displacement meter requirements LACT proving requirements Sediment and Water (S&W) determination API gravity determination Variance required for other methods (e.g. Coriolis) Incorporates numerous API standards (pre-1989)

Onshore Order 5 Gas Measurement Flange and pipe tapped orifice plates: AGA Report 3 (1985) Chart recorders: calibration outer 2/3 Gas sampling: BTU determined once per year Calculations: AGA Report 3 (1985)

NTL 2007-1 Electronic Flow Computers Parallels Onshore Order 5 requirements Adopts AGA-8, API 14.3.3 (1992), and portions of API 21.1 (1993) Display requirements Instantaneous DP, SP, Temp, Flow rate Yesterdays volume (except Wyoming) Calibration Transducer accuracy basis for calibration Operation Overall uncertainty 3% for >100 Mcf/day Low-flow cutoff 0.5 Calculations per API 14.3.3 (1992) are OK

NTL-4A Addresses beneficial use Defines avoidable vs. unavoidable loss Sets standards for venting and flaring: Emergencies Testing Prohibits venting/flaring of gas well gas Venting/flaring of oil well gas for 1 year if justified and approved Reporting of gas used beneficially, vented, flared, or lost

Existing Regulations 43 CFR Part 3160 3162.7-2 Oil Measurement 3162.7-3 Gas Measurement 3162.7-1 Disposition of Production Onshore Order 3 Site Security Onshore Order 4 Oil Measurement Onshore Order 5 Gas Measurement Statewide NTLs EFCs Federal Oil and Gas Royalty Management Act NTL-4A Venting, flaring, bene. use, loss

Proposed Revisions 43 CFR Part 3170 3174 Oil Measurement 3175 Gas Measurement 3173 Site Security, comm, OLM, FMP Federal Oil and Gas Royalty Management Act 3178 Beneficial Use 3179 Venting, flaring, avoidable loss 3170 Records, variances, defs

Proposed Revisions Common to Part 3170 Definitions Records, including purchasers/transporters Tampering Variances Appeals and enforcement Major/minor, corrective action, timeframe Implemented through policy

Proposed Revisions to Onshore Order 3 Site Security Facility Measurement Points Commingling Off-lease measurement

Subjects Covered Existing Seals tanks and LACTs Run tickets (sales) Theft or mishandling Self inspection Site security plan Site facility diagram Federal seals Proposed Revisions Seals tanks and LACTs Run tickets (sales) Record of all access Theft or mishandling Site facility diagram (added) Federal seals Facility Msmt. Points (FMP) Commingling Off-lease measurement

Facility Measurement Points Existing No consistent tracking of royalty meters or measurement facilities Measurement standards (Orders 4, 5) apply to sales and allocation facilities

#1 #2 #3 #4 #5 #6 #8 #7 #9 1-1 1-2 1-3 2-1 2-2 2-3 NM-16113 Measurement must be on the lease [CA, unit] unless otherwise approved

Facility Measurement Points Proposed Revisions FMP: A measurement facility used in the calculation of royalty Requires BLM approval and would be assigned an FMP number by the BLM Measurement standards (3174, 3175) would only apply to FMPs Allocation meters would not be FMPs

Facility Measurement Points New facilities would require FMP number prior to removal of production Existing facilities within 18 or 24 months FMP number would be shown on all measurement equipment All documentation (including OGORs) would require FMP number

FMP:70-33011-1234

FMP#: 70-33011-1234

Questions about FMPs Does the new requirement for FMP numbers apply to both oil and gas? Yes. An FMP would include: - A gas meter - A LACT - An oil tank facility (multiple tanks) Would the reporting on the OGOR (card C) be at an FMP number? Yes

Questions about FMPs How are downhole commingling situations impacted by the new FMP requirement? An FMP can measure oil and gas from more than one lease, CA, or PA Are the reporting changes going to be prospective or retroactive? Prospective Who will assign the FMP number? BLM How will existing facilities get FMP numbers assigned? Operators will apply to BLM

Commingling Existing BLM can approve commingling IM 2013-152: BLM can approve if

1-2 NMN-25533 Federal Lease 12.5% 2-2 NMN-25211 Federal Lease 12.5% #1#2#3 FMP Not FMPs Category 1: Allocation doesnt affect royalty

1-2 Fee lease 2-2 NMN-25211 Federal Lease 12.5% #1#2#3 FMP Not FMPs Category 2: Marginal volume wells

1-2 Fee lease 2-2 NMN-25211 Federal Lease 12.5% FMP Not FMPs Category 3: Other considerations - environmental

Commingling Proposed The provisions of IM 2013-152 would generally be codified Would apply to existing commingling approvals

Proposed Revisions to Onshore Order 4 Oil Measurement

Subjects Covered Existing Industry standards (old) Tank gauging Sampling S&W LACT components LACT proving Alternate methods Proposed Revisions Industry standards (new) Uncertainty standards Tank gauging Sampling S&W LACT components Coriolis Meas. System Meter proving Measurement tickets Alternate methods

Proposed Revisions to Onshore Order 5 Gas Measurement

Subjects Covered Existing Industry standards (old) Orifice plate and charts Low-flow exemptions Chart recorders Btu once per year AGA 3 (1985) calcs Proposed Revisions Industry standards (new) List of approved equipment 4 tiers based on flow rate Meter tube inspections Charts 100 Mcf/day Integration statements Gauge line standards Dynamic sampling frequency Gas sampling and reporting Transducer testing protocol Flow computer testing prot. Calculations

Subjects Covered - EGM Existing (NTLs) API 21.1, API 14.2 (old) Displayed data On-site data LFCO = 0.5 Verification Gas expansion (B&B) Atmos. pressure IV not required Proposed Revisions API 21.1, API 14.2 (new) Displayed data On-site data LFCO = 0.5 Verification (initial and rtn.) Gas expansion (API 14.3.1) Atmos. Pressure (no cntrct) IV required Reporting raw data

Sampling Frequency Common practice: Higher volume meters: monthly Lower volume meters: quarterly Why?

Royalty Policy Committee (2007): MMS and BLM should develop a procedure to determine the potential BTU variability of produced natural gas on a by-reservoir or by-lease basis, and estimate the implications for royalty payments MMS and BLM should adjust BTU frequency requirements for sampling and reporting on a case-by- case basis, or consider other regulatory requirements

BLM Heating Value Study The goals Determine heating value variability for each meter Correlate variability with variables (type of reservoir, type of lift, rich/lean gas, temperature) Figure out appropriate sampling frequency

BLM Heating Value Study The data

1040 1080 1120 1160 1200 1240 1280 2007 Heating Value, Btu/scf True heating value? Meter #1 Heating Value History - 2007

1040 1080 1120 1160 1200 1240 1280 2007 True heating value? Heating Value, Btu/scf Meter #1 Heating Value History - 2007

2 1040 1080 1120 1160 1200 1240 1280 2007 Average Heating Value, Btu/scf Meter #1 Heating Value History - 2007

1040 1080 1120 1160 1200 1240 1280 2007 Heating Value, Btu/scf Average Meter #1 Heating Value History - 2007

BLM Heating Value Study Conclusion Heating value variability is random and meter specific

BLM Heating Value Study Conclusions Heating value variability is random and meter specific Assume variability is randomly distributed around the true average Look at the accuracy of annual average heating value, not the accuracy of each sample

1040 1080 1120 1160 1200 1240 1280 2007 Heating Value, Btu/scf Average Meter #1 Heating Value History - 2007

1040 1080 1120 1160 1200 1240 1280 2007 Heating Value, Btu/scf

1040 1080 1120 1160 1200 1240 1280 2010 Heating Value, Btu/scf Meter #1 Heating Value History - 2010

1040 1080 1120 1160 1200 1240 1280 2010 Heating Value, Btu/scf

Average 1040 1080 1120 1160 1200 1240 1280 2007 Heating Value, Btu/scf Meter #2 Heating Value History - 2007

BLM Heating Value Study More conclusions: Set performance standard for average annual heating value uncertainty High historic variability = more samples Low historic variability = less samples Incentive for good sampling practice

Questions about Btu determination Currently, the BLM requires Btu sampling at least once a year, while ONRR is requiring it to be done at least twice a year. Who has jurisdiction on this issue? Both. Operators would comply with both requirements by sampling twice per year What could be changing? New sampling frequencies may be proposed in the 3175

Questions about venting and flaring Will the BLM require venting (non-tank) and flaring from gas operations to be reported on the OGOR? Is there a situation where this may be royalty bearing? -OGOR reporting requirements are the jurisdiction of ONRR -NTL-4A already requires the reporting of vented/flared volumes -Under NTL-4A it could be royalty bearing if it is unapproved or deemed to be avoidably lost

Questions about venting and flaring Will tank venting require measurement and reporting on the OGOR as flash gas or vapor recovery or some other report type? If this is NOT sold (ie. flared or combusted) would it be royalty bearing?

Status and Timeframe 3173, 3174, 3175 currently under review by the Secretarys Office Draft published in the Federal Register by July, 2015 Final published by August, 2016

Documents

Update of Onshore Orders 3, 4, and 5 Richard Estabrook, BLM Washington Office (Ukiah, CA) Petroleum Accountant’s Society of Oklahoma February 12, 2015