Federal Unit Agreements Laura Lindley Welborn Sullivan Meck & Tooley, P.C.

Federal Exploratory Units Authorized by Mineral Leasing Act to conserve the natural resources of any oil or gas pool, field or like area Generally much larger than a state spacing unit (usually no more than 25,000 acres) Operations on any committed tract deemed operations on each committed tract

Advantages of Unitization All committed leases can be extended by drilling a single well CAUTION: Merely committing a federal lease to a unit does not automatically extend the lease Can make surface access easier. Entek v. Stull Ranches (10th Cir. 2014)

Advantages of Unitization Acreage chargeability exemption Relief from state setback requirements

Commitment Status of Leases Fully Committed: All interest owners joined (100% WI and RI) Effectively Committed: All interests joined except overrides

Commitment Status of Leases Partially Committed: Federal: 100% operating rights but not record title Fee: 100% working interest but not royalty interest

Commitment Status of Leases Not Committed: Less than 100% working interest Unleased fee owners are treated as working interests to determine commitment status

Federal Lease Segregation Lands outside unit segregated into a separate lease and continue in effect for the original term but not less than 2 years from effective date of unit If term on date of segregation is indefinite extended term, both leases retain HBP status (but rental due on non-producing portion)

Public Interest Requirement Unit obligation well or wells must be timely drilled Unit is void ab initio if public interest requirement is not met, meaning any lease segregations and extensions are negated

Paying Unit Wells Paying well determination: quantities sufficient to repay the costs of drilling, completing and producing operations with a reasonable profit Not required to include extraordinary expenses such as costs of a pipeline or for lengthy fishing operations

Participating Areas The area reasonably proven to be productive in paying quantities For purposes of PA formation, paying quantities requires a well that will pay out Yates Well: One that will pay operating costs (and thus will extend the lease and the unit) but will not justify a PA

Participating Areas Size and shape are not prescribed by regulation – unit operator has significant discretion provided it has engineering and geologic support Some unit agreements (e.g., CBM units) prescribe the size or shape of the PA(s) Separate PAs for separate formations

Participating Areas Most BLM offices (CO, UT, WY) assume radial drainage in absence of contrary evidence “Circle-Tangent” method Some BLM offices (NM) tend to use state spacing units for PAs

Participating Areas (Vertical Wells) Initial Well PA Draw a circle around well using radius for assumed drainage area Legal subdivisions cut 50% or more are in PA

Participating Areas First Revision under circle tangent method If circles more than 4x radius apart, separate PAs

Participating Areas (Horizontal Wells) 40-acre circles around entry point of lateral to formation and around terminus 10-acre subdivisions cut by circles and tangents

Participating Areas All production allocated to each committed tract in a PA on an acreage basis No allocation of production to uncommitted tracts (except unleased federal land in post-1989 units) Uncommitted tracts may require formation of spacing unit/communitization agreement

Participating Areas In typical undivided type unit, costs of Exploratory Well borne based on WI ownership in Drilling Block Unit operating agreement prescribes maximum size of Drilling Block Participating area often does not match the size or shape of the Drilling Block Investment adjustment (Art. 13 of UOA) made so that costs are borne in same manner as ownership of production in the resulting P.A.

Participating Areas 640-acre Drilling Block A and B each bear 50% of the well costs

Participating Areas 360-acre P.A. A 160/360 44.45% B 80/360 22.22% 44.45% of production is allocated to Tract A 22.22% of production is allocated to Tract B 33.33% of production is allocated to Tract C Investment adjustment: C pays operator 33.33% of well costs Operator reimburses A and B for the excess costs they paid A 50% - 44.45% = 5.55% B 50% - 22.22% = 27.78%

Participating Areas Revisions Assume after an additional well is drilled, our 360-acre P.A. is expanded to a total 640 acres, owned as follows: Original P.A. Revised P.A. Tract A 44.45% (160) 37.5% (240) Tract B 22.22% (80) 43.75% (280) Tract C 33.33% (120) 18.75% (120) 360 640 Production occurring after the effective date of the revised P.A. will be allocated to Tracts A, B and C in the percentages shown for the Revised P.A. No re-allocation of production that occurred prior to effective date of P.A. revision Issue: BLM approval is generally several months or more after effective date of revision. How pay royalties in the meantime?

Participating Areas Revisions If the well causing the expansion is on federal lands, federal royalties shall be paid based on 100% of production from that well until the P.A. is approved, with retroactive true-up. Other royalties shall be impounded in a manner mutually acceptable to the owners of committed working interests until the P.A. is approved (Section 11 of unit agreement). Concerns about recouping large overpayments.

Participating Areas Revisions Example Royalty owner Smith has been receiving royalties of $1,000 per month based on 50% of production from the initial well allocated to the Smith tract. Operator expects the approved P.A. will allocate only 10% of production from the entire P.A. (2 wells) to Smith tract. Should Operator: Continue paying Smith on 50% of production from initial well and suspense all royalties on production from second well? Begin paying Smith on 10% of production from both wells?

Participating Areas Revisions Other Issues As further drilling occurs, P.A. continues to expand, requiring further revisions of each owner’s participating percentages (always with retroactive effective dates) Royalty owner confusion regarding changing volume allocations and, in some cases, recoupment of overpayments Payment deadlines under state royalty payment statutes

Term of Unit Unit will terminate if the obligation well is a dry hole or a Yates well unless a second well is commenced within 6 months after completion of first well Once a PA is approved, unit remains in effect for 5 years from the effective date of the initial PA

Term of Unit If drilling is occurring on non-PA lands on the 5th anniversary of initial PA, then unit continues in effect so long as diligent drilling continues with no more than 90 days between completion of one well on non-PA lands and commencement of next well on non-PA lands (for max of 5 additional years)

Term of Unit Unit contracts to the boundaries of existing (and pending) PAs at the 5th anniversary of initial PA or cessation of diligent drilling on non-PA lands No segregation of federal leases on partial elimination by unit contraction Federal leases entirely eliminated from unit are extended for remaining term but not less than 2 years

Term of Unit Agreement 2nd 5-year period 1/1/2000 Effective date of initial PA 1st 5-year period Plan of Development drilling . Typically, no drilling is required to continue unit in effect 1/1/2005 2nd 5-year period Automatic contraction unless continuous drilling is occurring outside PAs 1/1/2010 Possible one-time 2-year extension Continuous drilling obligation 1/1/2012 Unit contracts to boundaries of existing PAs

Term of Unit No automatic extension of fee leases upon elimination from unit Unit agreement can be voluntarily terminated by 75% of WIOs prior to discovery in paying quantities If voluntarily terminated before public interest requirement met, no extension for federal leases

Questions? Laura Lindley Welborn Sullivan Meck & Tooley, P.C. 1125 17th St., Ste. 2200 Denver, CO 80202 (303) 830-2500 llindley@wsmtlaw.com