Horizontal Drilling and the Pre-CA/CA issue PETROLEUM ACCOUNTING SOCIETY OF OKLAHOMA FEBRUARY 11-12, 2015

DISCUSSION OUTLINE ONRR Perspective Industry Perspective BLM Framing the Issue BLM Workloads/Backlogs Components of a Communitization Agreement Allocation Schedule Reservoir Management Lease Retention

DISCUSSION OUTLINE Proposed Solution to CA Processing Backlog BLM process streamlining BIA Role and Responsibility Departmental Goal Top Hole/Bottom Hole?

Well Completed on Federal Lands before CA Approval Gusher #1 well, API # Tract 1 Federal Tract 2 Federal Tract 3 State or Fee ONRR

Well Completed on Federal Lands before CA Approval Key Points – Before CA Approval: OGOR Reports – Report as lease basis until CA approval. ONRR-2014 – Report as lease basis until CA approval. Tract 1 Federal Tract 2 Federal Tract 3 State or Fee ONRR

Well completed before CA approval; located on non-Federal Tract 3 Question: What if the well 3 was located on Fee land? Answer: Before CA Approval - Because the well is not located on a Federal Lease, no OGOR Reports or Form ONRR-2014s are required. After CA Approval - File original OGOR Reports and Form ONRR-2014s retroactive to the CA effective date. Tract 1 Federal Tract 2 Federal Tract 3 State or Fee ONRR

Reporting on Indian Properties Prior to Agreement Approval Assume 640 acre spacing with 4 Indian allotted leases, each 160 acres State spacing calls for a CA Indian Lease 1 Indian Lease 2 Indian Lease 4 Indian Lease 3 ONRR

What’s the Problem - Perspective of Individual Indian Mineral Owners: Royalty Reporting Pending CA Approval – Well Located in Indian Allotted Lease Indian lease 1 would receive 100% of royalties until the CA is approved. Leases 2-4 are each rightfully entitled to 25% of royalties, but would receive nothing without an allocation schedule. Until BLM approves a CA or PA, there is no allocation schedule from which ONRR can distribute royalties. Until a CA or PA is approved, ONRR can only distribute royalties based on the lease upon which the well is located. Many individual mineral owners rely on royalties for their livelihood but until an agreement is approved, ONRR cannot pay the mineral owners of Indian Leases 2, 3 and 4. ONRR

What’s the Problem - Perspective of an Indian Lessee with a Royalty Overpayment Royalty Reporting After CA Approval - limitation on recoupment of overpayments Once the CA is approved, the production from the well must be reallocated to all of the leases in the CA and the OGOR and 2014s must be corrected. The lessee of Indian Lease #1 must reallocate production and royalties but because Indian lands are involved, the lessee’s ability to recoup the overpayment is limited. Recoupment of overpayments resulting from retroactive agreement approvals are limited on Indian lands: No more than 50% recouped per month for allottees No more than 100% recouped per month for tribes The 50% recoupment is meant to protect the income of individual mineral owners, many of whom rely on royalties for their livelihood. ONRR

Historic Problems with Delayed CA Approval Delay in royalty reporting All royalties knowingly paid incorrectly until CA is approved Duplicate royalty payments Higher interest on underpaid than overpaid amounts Causes a famine/feast effect with regards to States and Counties Complex correction process Industry Perspective

Benefits of PCA/Streamlined CA Process More timely and accurate reporting to all royalty owners State and County agencies able to budget more accurately Time for BLM to perform due dilligence Reduces/eliminates the need for large amendments Reduces/eliminates *challenges* of recouping royalties PCA process/Streamlined CA process working well in North Dakota and New Mexico Industry Perspective

Challenges of Recouping Overpaid Royalty Recoupment limits Tribe – 100% of net current revenue Allottee – 50% of net current revenue Variable production rates can impact recoupment Industry Perspective

Causative Factors for the Backlog Not Rocket Science BLM is fully capable of performing the technical work associated processing CAs However it does take a certain level of technical expertise. If it isn’t Rocket Science then what is the problem? BLM

Causative Factors for the Backlog Budget and Staffing Budget BLM Oil and Gas Program Funding declined from 2008 to 2013 A portion of funding for the existing program is from onshore rental receipts which are declining as industry is either relinquishing leases or drilling them, thus taking them out of rental status. A portion of the funding is from APD fee receipts. The National Defense Authorization Act raised the APD fee to $9,500 indexed to inflation, with a portion of the collections being distributed back to the office which processed the APD. BLM

Causative Factors for the Backlog Budget and Staffing Staffing Loss of oil and gas staff to industry. Aging workforce resulting in the retirement of key individuals. So though while not rocket science this work does require a certain level of expertise and training to achieve that level. High cost of living in certain areas makes it difficult under the federal salary structure to attract applicants. BLM

Causative Factors for the Backlog Deficient CA Applications The Big Three Survey errors, many of which are associated with rivers and streams Properly described or matched leases (Federal/Indian) to acceptable surveys Not recognizing prior existing rights associated with existing CAs BLM

Causative Factors for the Backlog Deficient CA Applications Other Causes Commodity Errors Formation Errors Vertical vs. Horizontal Missing working interest owner signatures BLM

Causative Factors for the Backlog Delays - Additional Wells in and Existing CA Commodity Errors Formation Errors Operator Errors Timing Errors BLM

Possible Deficiency Solutions Submit a Better CA Application: Have your irregular/river surveys reviewed by BLM’s Cadastral Survey prior to submission Submit your CA applications timely, perhaps even before drilling the first well Make sure your CA application matches the description and acreage in your BLM/BIA lease documents Obtain signatures for all working interest owners Make sure commodity and formation match your well Check for prior existing CAs BLM

30 U.S.C. § 226(m), third unnumbered paragraph. It reads as follows: When separate tracts cannot be independently developed and operated in conformity with an established well-spacing or development program, any lease, or a portion thereof, may be pooled with other lands, whether or not owned by the United States, under a communitization or drilling agreement providing for an apportionment of production or royalties among the separate tracts of land comprising the drilling or spacing unit when determined by the Secretary of the Interior to be in the public interest, and operations or production pursuant to such an agreement shall be deemed to be operations or production as to each such lease committed thereto. Authority and Criteria for a Communitization Agreement BLM

The Three Criteria for a Communitization Agreement 1.Lease cannot be independently developed and operated in conformity with an established well-spacing or development program; (Reservoir Management – BLM) 2.Provides for an apportionment of production or royalties; and, (Allocation Schedule – BLM & ONRR) 3. Operations or production pursuant to such an agreement shall be deemed to be operations or production as to each such lease committed thereto. (Lease Management – BLM/BIA ) BLM

Pre-CA’s: Concerns The benefit: an allocation schedule for ONRR thus earlier distribution of royalties on an agreement basis and less reporting burden for industry BLM’s concerns: legal insufficiency – no BLM official has approved the allocation schedule. Does not hold leases past their primary term (federal leases are held by ability to produce; Indian leases are held by actual production. (BLM/BIA – lease management) No incentive for further development (BLM - reservoir management) Additional workload for understaffed BLM and BIA offices BLM

BLM STREAMLINING Resolution of Backlogs by re- engineering the CA submittal and approval process Require Communitization Agreement application as Condition of Approval with the Application for Permit to Drill Adjudicate only the Federal/Indian Interests Allow the Operator to self certify possession of signatures

BLM STREAMLINING Resolution of Backlogs by re-engineering the CA submittal and approval process Federal/Indian Leases provided by the Operator, A single aggregate submittal of the State leases and of the fee interests.

For the Federal and/or Indian Tracts :  Lease Serial No.:  Lease Date:  Lease Term:  Lessor:  Lessee on effective date of agreement if different from present lessee:  Present Lessee: AB Company  Description of Land Committed :  Number of Acres:  Royalty Rate;  Name and Percent ORRI Owners:  Name and Percent WI Owners: FORM B

For the non-Federal and/or non-Indian Tracts  Lease Serial No.:  Lease Date:  Lease Term:  Lessor:  Lessee on effective date of agreement if different from present lessee:  Present Lessee:  Description of Land Committed :  Number of Acres:  Royalty Rate;  Name and Percent ORRI Owners:  Name and Percent WI Owners: FORM B

BIA STREAMLINING BIA Roles and Responsibilities BLM recommends to BIA whether to approve an Indian CA or not to approve it. BIA has been adjudicating the leases in the same manner that BLM has been adjudicating the leases. The BIA then approves or rejects the CA. BIA is the authorized officer.

BIA STREAMLINING BIA Roles and Responsibilities To streamline the BIA process, BIA and BLM will develop operating procedures to eliminate duplicative work. Thus after BLM adjudication, BIA will only have to do a quality check of the trust leases, and then obtain the Authorized Officer’s signature.

DEPARTMENTAL GOAL The Departmental Goal is to sunset the Pre-CA process as soon as practicable. For all states, with the exception of ND and WY, BLM believes the streamlined CA process will achieve this goal in the next few months. For ND and WY a greater staffing emphasis will be provided to expedite achieving the goal. A “Strike Team” has been developed for ND, deployment expected by mid year.

TOP HOLE/BOTTOM HOLE EVOLUTION OF THE ISSUE Federal Lease #1 Under vertical well technology – there was no issue as both locations were on the same lease. Each well bore could be entered into AFMSS as a discrete entity with a single lease affiliation. Federal Lease #2

TOP HOLE/BOTTOM HOLE EVOLUTION OF THE ISSUE Federal Lease #1 Tieing the APD to the top hole federal lease is logical because this is where the well pad resides. Tieing the APD to the bottom hole lease was a logical extension from directional wells where the target was the bottom hole. BLM CA Handbook last updated July 7, 1988 – did not provide guidance. AFMSS has not been updated to accept more than one lease number per APD. With Hydraulic Fracturing regulations nearing completion, updating the CA Handbook has become a priority for BLM. Federal Lease #2 Fee Lease #1 Indian Lease #1