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Home My WebLink AboutGas-NicolaiCk-UndefAlaska Oil and Gas Conservation Commisssion - Pool Statistics, Unit and Pool Home Orders Staff Calendar Contact Us AOGCC Pool Statistics Nicolai Creek Unit, Undef Gas Pool Alaska Oil and Gas Conservation Commission > Annual Reports > Pool Statistics - 2004: Updated 05 August 2005 Page: 1 > 2 Operator:Aurora Gas LLC Discovery Well:Texaco Inc. Nicolai Creek State No 1A Permit #165-027 API No. 50-283-10020-00-00 Sec. 30, T11N, R12W,SM Depth: 8,338’ MD / 7,979' TVD May 12, 1966 Status:Producing Location:Cook Inlet Basin Area Loc. Map Field Loc. Map DNR Unit Map Orders:Complete List Strat Column Production:Prod Chart Prod Report Prod Data Gas (mcf)Water (bbls)Disposed Fluids (bbls) Cumulative 3,189,351 32,201 0 2001 Total 277,798 4,231 0 2002 Total 605,050 17,550 0 2003 Total 261,696 10,338 0 2004 Total 982,752 82 0 2003 Rate (/d)717 28 0 2004 Rate (/d) 2,692 0 0 Change (%)276% - - Continued: 1 > 2 Home Orders Staff Calendar Contact Us Webmaster http://www.state.ak.us/local/akpages/ADMIN/ogc/ann...04/Gas_Pools/Nicolai%20Creek%20-%20Gas/1_Gas_1.htm [3/28/2008 6:16:42 PM] Alaska Oil and Gas Conservation Commisssion - Pool Statistics, Unit and Pool Home Orders Staff Calendar Contact Us AOGCC Pool Statistics Nicolai Creek Unit, Undef Gas Pool Alaska Oil and Gas Conservation Commission > Annual Reports > Pool Statistics - 2004: Updated 05 August 2005 Page: 1 > 2 Field Development Information: Wells In Field Type Well Status 2004 2003 2002 2001 2000 Producer Gas 4 4 2 1 1 Injector Disposal 0 0 0 0 0 Non-Operating Suspended 1 1 2 2 2 Abandoned 5 5 5 5 5 Total 10 10 9 8 8 Permitted Wells in Field: Type Well Status 2004 2003 2002 2001 2000 Development New 0 0 2 0 0 Sidetrack 0 0 1 0 0 Multilateral 0 0 0 0 0 Service New 0 0 1 0 0 Exploration New 0 0 0 0 0 Total 0 0 4 0 0 Active Completions in Pool (Month of December): Type Well Status 2004 2003 2002 2001 2000 Gas Producer Flowing 2 3 1 1 0 Other 0 0 0 0 0 Shut-In 2 1 0 0 1 Disposal Disposal Injector 0 0 0 0 0 Shut-In 0 0 0 0 0 Total 4 4 1 1 1 Reservoir Properties: Beluga & U Tyonek Formations Description 2004 2003 2002 2001 2000 Reference Datum - ft. below sea level 1300-3287 1300-3287 1924 1924 1924 Temperature - ° F 66-95 66-95 105 105 105 Porosity - % 21-29 21-29 2 2 17 Permeability - md 20-200 20-200 --- Swi - % 30-57 30-57 50 50 50 Orig. Press. - psi 690-1680 690-1680 980 980 980 Curr. Reservoir Press. - psi 330-1640 674-1681 -- 850 Curr. Reservoir Press. - Test Date Dec-04 Nov-03 -- Sep-91 Gas Specific Gravity (Air = 1.0) 0.56 0.56 - 0.56 0.57 Gross Pay - ft. 127-190 127-190 - 140 128 Net Pay - ft. 60-100 60-100 - 140 128 Continued: 1 > 2 Home Orders Staff Calendar Contact Us Webmaster http://www.state.ak.us/local/akpages/ADMIN/ogc/ann...04/Gas_Pools/Nicolai%20Creek%20-%20Gas/1_Gas_2.htm [3/28/2008 6:16:50 PM] State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through NICOLAI_CREEK_ Oct 1968 0 2883 029 1 Nov 1968 0 4473 030 1 Dec 1968 0 4914 031 1 Mar 1969 0 27795 031 1 Apr 1969 0 41371 030 2 May 1969 0 47933 031 1 Jun 1969 0 32103 030 2 Jul 1969 0 26543 031 2 Aug 1969 0 28632 031 1 Sep 1969 0 28625 030 1 Oct 1969 0 17602 031 2 Nov 1969 0 13187 030 2 Dec 1969 0 19618 031 1 Jan 1970 0 21041 031 1 Feb 1970 0 18452 028 1 Mar 1970 0 18695 031 1 Apr 1970 0 14410 030 1 May 1970 0 15098 031 1 Jun 1970 0 11304 030 1 Jul 1970 0 10665 031 1 Aug 1970 0 17037 031 1 Sep 1970 0 16577 030 1 Oct 1970 0 20766 031 1 Nov 1970 0 20197 030 1 Dec 1970 0 17669 031 1 Jan 1971 0 20738 031 1 Feb 1971 0 19327 028 1 Mar 1971 0 11582 031 1 Apr 1971 0 12446 030 1 May 1971 0 9351 031 1 Jun 1971 0 15309 030 1 Jul 1971 0 16250 031 1 Aug 1971 0 15485 031 1 Sep 1971 0 5295 030 1 Oct 1971 0 5897 031 1 Nov 1971 0 4185 030 1 Dec 1971 0 4962 031 1 Jan 1972 0 6333 031 1 Feb 1972 0 7940 029 1 Mar 1972 0 5781 031 1 Apr 1972 0 6125 030 1 May 1972 0 7075 031 1 Jun 1972 0 6157 030 1 Jul 1972 0 7789 029 1 Aug 1972 0 5068 031 1 Sep 1972 0 777 06 1 Oct 1972 0 8407 031 1 Nov 1972 0 3061 030 1 Dec 1972 0 1368 031 1 5/27/2005 Page 1 of 6 State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through Jan 1973 0 1446 031 1 Feb 1973 0 118 028 1 Mar 1973 0 179 031 1 Apr 1973 0 98 030 1 May 1973 0 0 00 1 Jun 1973 0 825 030 1 Jul 1973 0 1076 031 1 Aug 1973 0 521 031 1 Sep 1973 0 326 030 1 Oct 1973 0 109 031 1 Nov 1973 0 1116 030 1 Dec 1973 0 0 00 1 Jan 1974 0 0 00 1 Feb 1974 0 0 00 1 Mar 1974 0 0 00 1 Apr 1974 0 2353 030 1 May 1974 0 702 031 1 Jun 1974 0 739 030 1 Jul 1974 0 985 031 1 Aug 1974 0 2639 031 1 Sep 1974 0 2394 030 1 Oct 1974 0 209 031 1 Nov 1974 0 410 030 1 Dec 1974 0 100 031 1 Jan 1975 0 942 031 1 Feb 1975 0 597 028 1 Mar 1975 0 4582 031 1 Apr 1975 0 4347 030 1 May 1975 0 7062 031 1 Jun 1975 0 6840 030 1 Jul 1975 0 8548 031 1 Aug 1975 0 11090 031 1 Sep 1975 0 11086 030 1 Oct 1975 0 13067 031 1 Nov 1975 0 8733 030 1 Dec 1975 0 6469 031 1 Jan 1976 0 6840 031 1 Feb 1976 0 6969 029 1 Mar 1976 0 3890 031 1 Apr 1976 0 10785 030 1 May 1976 0 9308 031 1 Jun 1976 0 6750 030 1 Jul 1976 0 11933 031 1 Aug 1976 0 11517 028 1 Sep 1976 0 11700 030 1 Oct 1976 0 14086 031 1 Nov 1976 0 8429 030 1 Dec 1976 0 6199 031 1 Jan 1977 0 8419 016 1 Feb 1977 0 8504 025 1 Mar 1977 0 3058 01 1 5/27/2005 Page 2 of 6 State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through Apr 1977 0 0 00 1 May 1977 0 0 00 1 Jun 1977 0 0 00 1 Jul 1977 0 7904 031 1 Aug 1977 0 4369 018 1 Sep 1977 0 0 00 1 Oct 1977 0 10 02 1 Nov 1977 0 0 00 1 Dec 1977 0 0 00 1 Jan 1978 0 0 00 1 Feb 1978 0 0 00 1 Mar 1978 0 0 00 1 Apr 1978 0 0 00 1 May 1978 0 0 00 1 Jun 1978 0 0 00 1 Jul 1978 0 0 00 1 Aug 1978 0 0 00 1 Sep 1978 0 0 00 1 Oct 1978 0 0 00 1 Nov 1978 0 0 00 1 Dec 1978 0 0 00 1 Jan 1979 0 0 00 1 Feb 1979 0 0 00 1 Mar 1979 0 0 00 1 Apr 1979 0 0 00 1 May 1979 0 0 00 1 Jun 1979 0 0 00 1 Jul 1979 0 0 00 1 Aug 1979 0 0 00 1 Sep 1979 0 0 00 1 Oct 1979 0 0 00 1 Nov 1979 0 0 00 1 Dec 1979 0 0 00 1 Jan 1980 0 0 00 1 Feb 1980 0 0 00 1 Mar 1980 0 0 00 1 Apr 1980 0 0 00 1 May 1980 0 0 00 1 Jun 1980 0 0 00 1 Jul 1980 0 0 00 1 Aug 1980 0 0 00 1 Sep 1980 0 0 00 1 Oct 1980 0 0 00 1 Nov 1980 0 0 00 1 Dec 1980 0 0 00 1 Jan 1981 0 0 00 1 Feb 1981 0 0 00 1 Mar 1981 0 0 00 1 Apr 1981 0 0 00 1 May 1981 0 0 00 1 Jun 1981 0 0 00 1 5/27/2005 Page 3 of 6 State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through Jul 1981 0 0 00 1 Aug 1981 0 0 00 1 Sep 1981 0 0 00 1 Oct 1981 0 0 00 1 Nov 1981 0 0 00 1 Dec 1981 0 0 00 1 Jan 1982 0 0 00 1 Feb 1982 0 0 00 1 Mar 1982 0 0 00 1 Apr 1982 0 0 00 1 May 1982 0 0 00 1 Jun 1982 0 0 00 1 Jul 1982 0 0 00 1 Aug 1982 0 0 00 1 Sep 1982 0 0 00 1 Oct 1982 0 0 00 1 Nov 1982 0 0 00 1 Dec 1982 0 0 00 1 Jan 1983 0 0 00 1 Feb 1983 0 0 00 1 Feb 2001 0 4146 2203 1 Mar 2001 0 0 00 1 Apr 2001 0 0 00 1 May 2001 0 0 00 1 Jun 2001 0 0 00 1 Jul 2001 0 210 03 1 Aug 2001 0 0 00 1 Sep 2001 0 9156 40612 1 Oct 2001 0 111457 142731 1 Nov 2001 0 115863 142730 1 Dec 2001 0 36966 75115 1 Jan 2002 0 38117 102426 1 Feb 2002 0 74394 142227 1 Mar 2002 0 99891 140331 1 Apr 2002 0 74638 140229 1 May 2002 0 74454 159231 1 Jun 2002 0 56774 162330 1 Jul 2002 0 43924 151731 1 Aug 2002 0 33787 148731 1 Sep 2002 0 34878 149830 1 Oct 2002 0 23539 135726 1 Nov 2002 0 21880 155625 1 Dec 2002 0 28774 166931 1 Jan 2003 0 22384 150531 1 Feb 2003 0 12436 126128 1 Mar 2003 0 7372 97621 1 Apr 2003 0 13388 157930 1 May 2003 0 17536 166031 1 Jun 2003 0 15844 159530 1 Jul 2003 0 12803 144528 1 Aug 2003 0 50 02 1 5/27/2005 Page 4 of 6 State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through Sep 2003 0 1501 030 1 Oct 2003 0 1846 031 1 Nov 2003 0 4931 13511 2 Dec 2003 0 81524 13029 2 Jan 2004 0 62093 016 2 Feb 2004 0 5360 07 2 Mar 2004 0 19707 08 2 Apr 2004 0 25135 010 2 May 2004 0 77632 031 2 Jun 2004 0 15493 07 2 Jul 2004 0 39744 219 2 Aug 2004 0 45870 6230 2 Sep 2004 0 34153 632 2 Oct 2004 0 27067 131 2 Nov 2004 0 19507 123 2 Dec 2004 0 13221 118 2 Jan 2005 0 0 00 2 Feb 2005 0 0 00 2 Mar 2005 0 6 01 2 Apr 2005 0 8278 09 2 0 2412405 32140Pad Total NICOLAI_CREEK_ Dec 1968 0 13919 031 1 Jan 1969 0 55385 031 1 Feb 1969 0 48075 028 1 Nov 2003 0 1099 522 1 Dec 2003 0 0 0 1 Jan 2004 0 0 00 1 Feb 2004 0 0 00 1 Mar 2004 0 875 05 1 Apr 2004 0 0 00 1 May 2004 0 0 00 1 Jun 2004 0 0 00 1 Jul 2004 0 0 00 1 Aug 2004 0 0 00 1 Sep 2004 0 0 00 1 Oct 2004 0 0 00 1 Nov 2004 0 0 00 1 Dec 2004 0 0 00 1 Jan 2005 0 0 00 1 Feb 2005 0 0 00 1 Mar 2005 0 0 00 1 Apr 2005 0 0 00 1 0 119353 52Pad Total NICOLAI_CREEK_ Nov 2003 0 793 01 1 Dec 2003 0 68189 018 1 Jan 2004 0 38620 015 1 Feb 2004 0 573 01 1 5/27/2005 Page 5 of 6 State of Alaska, Oil and Gas Conservation Commission Production History for: Month Oil (BBL)Gas (MCF)Water (BBLDaysProd Wells NICOLAI CREEK, NORTH UND GAS Pool Jan 1958 Through Mar 2004 0 31840 013 1 Apr 2004 0 59576 022 1 May 2004 0 79158 031 1 Jun 2004 0 53103 019 1 Jul 2004 0 36134 416 1 Aug 2004 0 72869 128 1 Sep 2004 0 76400 130 1 Oct 2004 0 68267 131 1 Nov 2004 0 48475 129 1 Dec 2004 0 31880 118 1 Jan 2005 0 508 01 1 Feb 2005 0 112 01 1 Mar 2005 0 24 01 1 Apr 2005 0 15813 09 1 0 682334 9Pad Total 0 3,214,092 32,201Pool Total 5/27/2005 Page 6 of 6 Findings and Decision of the Director of the Division of Oil and Gas APPROVAL OF THE REVISED NICOLAI CREEK UNIT AREA, REVISED PARTICIPATING AREAS A and B, AND FORMATION OF THE BELUGA PARTICIPATING AREA Under a Delegation of Authority from the Commissioner of the State Of Alaska Department of Natural Resources March 10, 2005 Table of Contents I. DECISION SUMMARY ........................................................ 2 II. BACKGROUND AND APPLICATION HISTORY ...................................... 2 III. PARTICIPATING AREA DECISION CRITERIA ................................... 5 IV. FINDINGS ................................................................ 8 V. DECISION ................................................................. 9 2 I. DECISION SUMMARY Aurora Gas, LLC (Aurora), as Nicolai Creek Unit (NCU) operator and sole working interest owner, applied to revise the existing participating areas, form the Beluga Participating Area, and revise the Nicolai Creek Unit Area (the Application). The State of Alaska Department of Natural Resources, Division of Oil and Gas (the DNR or the Division, as appropriate) approves the Application as follows: 1. Participating Area A is revised to reflect the current geologic and engineering interpretation for the reservoir and is renamed the South Participating Area (SPA). 2. Participating Area B is renamed the North Participating Area (NPA). 3. The new Beluga Participating Area (BPA) is approved. 4. A portion of federal lease AA-8426 is added to the NCU and the aerial extent of the Unit is revised to encompass the three PAs. As before, the unit area is limited to its approved participating areas. 5. Aurora shall work with the Division’s Royalty Accounting Section to revise all royalty and operator reports back to November 1, 2003. The production must be allocated based on the approved tract participation schedules for each participating area. Aurora submitted geologic and well data that indicate the revised SPA and proposed BPA are capable of producing or contributing to the production of hydrocarbons in paying quantities, which justifies revising the SPA and the NCU, and forming the BPA. Attachment 1 is a map showing the old and new NCU boundary. Attachment 2 is a map showing the old and new SPA boundary. Attachment 3 is Exhibit A to the NCU Agreement showing the approved boundaries for the NCU, BPA, SPA, and NPA. The Division also approves Exhibits B, B-1, B-2 and B-3 to the NCU Agreement (Attachments 4 through 7), the tract allocation schedules for each of the PAs. The tract allocation schedules equitably allocate production and costs among the leases in the NCU. II. BACKGROUND AND APPLICATION HISTORY Texaco formed the Nicolai Creek Unit and Participating Areas A and B in 1968. It drilled the Nicolai Creek State No. 1-A well (NCS-1A) in the Participating Area B and tested the well, but no facilities or pipelines were built to facilitate sustained production. It also drilled the Nicolai Creek No. 2 well (NCU-2) and the Nicolai Creek No. 3 well (NCU-3). NCU-2 tested gas from Participating Area A for nine months in 1968 and 1969. Facilities and a pipeline were installed for Participating Area B and NCU-3 produced from Participating area B from 1969 through 1977. 3 In 1973, the NCU boundary contracted to the discontiguous lands within Participating Areas A and B. Unocal and Marathon acquired the field in 1988, each holding 50% working interest, and Unocal was the designated unit operator. Beginning in 1998, AS 38.05.180(f)(5) provided for a temporary royalty reduction to encourage development of certain fields in the Cook Inlet Basin, including Nicolai Creek. The Statute establishes a royalty rate of five percent on the first 25,000,000 barrels of oil and 35,000,000,000 cubic feet of gas produced from eligible fields within 10 years of initial production for sale, if production for sale commenced before January 1, 2004. To qualify for the reduced royalty rate on production from the Nicolai Creek Field, the operator was required to submit a written plan to the Alaska Oil and Gas Conservation Commission (AOGCC) in accordance with AS 31.05.030(i). This generous economic incentive was intended to encourage Unocal to bring the Nicolai Creek Unit on production earlier than planned. In November 2000, Unocal and Marathon assigned their interests to Aurora. Aurora became the operator with 100 percent working interest in the NCU. Aurora successfully restarted sustained production in the NCU-3 well in September 2001 and the AOGCC approved its written plan submitted under AS 31.05.030(i), which qualified the field for the royalty reduction. By letter date July 12, 2002, Aurora requested an order from the AOGCC allowing a spacing exception to drill and test the Nicolai Creek Unit No. 1B (NCU-1B) and No. 8 (NCU-8) wells and to recomplete and test the NCU-2 well. The AOGCC issued Conservation Order No. 478 (Attachment 9), on September 5, 2002, which approved Aurora’s request for spacing exceptions but provided that the wells could not be placed on regular production until the AOGCC took additional action to offset any advantage Aurora may have had over other mineral owners by reason of the wells having been drilled to the exception locations. Aurora did not drill the NCU-8 well because it encountered a shallow obstruction while driving conductor pipe, but permitted and drilled NCU No. 9 (NCU-9) as a replacement well. On September 2, 2003, Aurora submitted an application to the Division for approval to revise the participating areas and the NCU boundary. The Division immediately notified Aurora that its application was incomplete and began working with Aurora to remedy the deficiencies. It quickly became apparent that the process was going to take an extended period of time due to the number of parties involved, and the unresolved land ownership and title issues. The Division invited the Mental Health Trust Land Office (TLO) to participate in all pertinent Application communications, discussions, and meetings between Aurora and the Division because they are an adjacent mineral interest owner. As early as August 12, 2003, the Division’s goal was to include the TLO throughout the process and arrive at a fair decision that the TLO would support. In the interim, Aurora proposed to report production from the NCU-1B and NCU-2 wells to the Division at a five percent royalty rate, and production from the NCU-9 to the Bureau of 4 Land Management (BLM) using a 12.5 percent royalty rate. On September 25, 2003, the Division, the TLO and BLM agreed with this interim royalty reporting payment methodology, on condition that, upon approval of the final Application, Aurora shall submit revised royalty and operator reports to the Division and BLM retroactive to the first day of production (See Attachment 12). On October 9, 2003, Aurora submitted a revised Application, to the Division, along with additional supporting confidential geologic and engineering data. On October 16, 2003, the AOGCC issued Conservation Order No. 478A (Attachment 10) allowing regular production from the NCU-1B, NCU-2 and NCU-9 wells using the interim reporting methodology. In November 2003, Aurora completed pipeline and facility construction for PA-B and initiated production from the NCU-2 and NCU-9 wells. The Division worked with Aurora, the BLM and the TLO on the Application, and on November 4, 2003, the Division determined that the Application included all of the items listed in 11 AAC 83.306 and constituted a complete application for public notice. The Division issued a public notice of the Revised Application on November 5, 2003, which DNR posted on the State’s web page. The notice was published in the Anchorage Daily News and the Peninsula Clarion on Sunday, November 9, 2003. The public notice invited interested parties and members of the public to submit comments on the Application by December 9, 2003. The Division received two comment letters in response to the pubic notice. The first letter, submitted by the TLO to document its involvement in the process of approving the Application, is attached to this Decision (Attachment 11). The second letter was from the Kenai Peninsula Borough, which reviewed the proposed unit expansion for consistency with the Kenai Peninsula Borough Coastal Management Program enforceable policies. The Kenai Peninsula Borough had no objection to approval of the Application. On January 7, 2004, Aurora submitted a request to suspend the Application process until such time that the technical details could be resolved. On January 8, 2004, the Division approved the suspension of the Application and encouraged Aurora to continue working with the interested parties to reach agreement on the revised unit and participating area boundaries. After working with the various parties, on and off for approximately one year, on January 21, 2005, Aurora submitted a final, revised Application that included new tract participation schedules and a proposal to create an additional participating area (BPA). The Application proposes to include a portion of federal lease AA-8426, approximately 45.30 acres, in the NCU. Aurora is the only working interest owner, but there are approximately 16 overriding royalty owners. There is geologic and engineering evidence to support the formation of the BPA to develop 5 the Beluga Reservoirs within the revised NCU. The data also supports revising the SPA to develop the Tyonek Reservoirs under a unified plan of development. III. PARTICIPATING AREA DECISION CRITERIA AS 38.05.180(p) gives DNR the authority to approve an oil and gas unit. The DNR Commissioner (Commissioner) reviews unit and participating area applications under AS 38.05.180(p) and 11 AAC 83.301 – 11 AAC 83.395. By memorandum dated September 30, 1999, the Commissioner approved a revision of Department Order 003, and delegated this authority to the Division Director (Director). Under 11 AAC 83.303(a), the Director will approve the Application upon finding that it will: 1) promote the conservation of all natural resources; 2) promote the prevention of economic and physical waste; and 3) provide for the protection of all parties of interest, including the state. Subsection .303(b) sets out six criteria that the Director will consider in evaluating the Application. A discussion of the subsection .303(b) criteria, as they apply to the Application, is set out directly below, followed by the Director’s findings relevant to subsection .303(a) and the Director’s conditional approval of the Application. A participating area may include only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. 11 AAC 83.351(a). “Paying Quantities” means: Quantities sufficient to yield a return in excess of operating, costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are sufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. 11 AAC 83.395(4) 1) The Environmental Costs and Benefits Approval of the BPA and the revision of the SPA has no environmental impact. This Decision is an administrative action and does not authorize any surface activity. Potential effects on the environment are analyzed when permits to conduct exploration or development in the unit area are reviewed. In fact, unitized development has less impact on the environment than development on a lease-by-lease basis. 2) The Geological and Engineering Characteristics of the Proposed PAs The State’s regulations provide that a unit must encompass the minimum area required to include all or part of one or more oil or gas reservoirs, or potential accumulations. 11 AAC 83.356(a). DNR technical staff evaluated all data provided by the unit operator including 6 geologic cross sections, structure maps, electric log analyses, and interpreted seismic data to determine if the proposed unit area met the regulatory criteria. The reservoir sandstones of the NCU belong to the Oligo/Miocene Tyonek and Beluga Formations. Only those sands of the Tyonek Formation are currently producing. Deposition of these sands occurred within the Cook Inlet Basin, a feature characterized as an elongate, northeast trending, fault-bounded forearc basin that extends from the Matanuska Valley south along the Alaska Peninsula. The northwestern reaches of the Cook Inlet forearc basin are defined by a series of tight anticlines and associated structures that deform the Tertiary section and provide traps for both oil and gas. These features are part of a transpressional regime that results from strain transfer between the Castle Mountain Fault to the north and Bruin Bay Fault to the west. The structures manifested within the NCU have evolved through such processes. Subsurface geology of the NPA of the NCU indicates a combination structural and stratigraphic trap with gas trapped in Upper Tyonek sandstones. Sandstone units are draped over a four-way closure anticline formed along a southward-plunging axis on the west side of an eastward-verging fault (interpreted to be the northern extension of the Trading Bay fault). A similar setting exists in the subsurface of the SPA of Upper Tyonek gas bearing sandstones trapped within a fold and closed against a dominant west-east cross-fault (the Nicolai Cross Fault) that splays off the aforementioned Trading Bay Fault to the east. The Nicolai Cross Fault appears to separate the structure of the NPA from that of the SPA. From a maximum of approximately 500-600 feet in the east, the fault throw diminishes westwards. Within the NPA and SPA, reservoirs sandstones are restricted to the Upper Tyonek Formation. Eight individual sand members have been identified from log correlation and mapped across the Nicolai Creek field. Within the Nicolai Creek field, individual sands have been assigned names based on standardized industry palynological zonation. The sandstones are within the Carya 2 palynological zone and have been subdivided using an appropriate numeric designation (2-1.1, 2-1.2, 2-2.1, 2-2.2, 2-2.3, 2-4.2, 2-5.1, and 2-6.1). Log data indicate the NCU wells show the relative conformity of the shallower Carya 2-1 through Carya 2-23 section with some possible expansion of the deeper Carya 2-4.2 through Carya 2-6.1 section. The apparent expansion of the deeper section in the NCU-2 well could be explained by faulting. Gas appears trapped in the Upper Tyonek Formation in unconsolidated, non-marine sandstone reservoirs between 1,680 and 3,475 feet subsea true vertical depth (SSTVD). Since the Tyonek reservoirs of both the NPA and SPA are stacked sandstone bodies, the composite areas of the reservoir extent, which is controlled by structure and sandstone distribution and confirmed by seismic and well data, are summed together to define the outline of the SPA and NPA areas. The BPA is defined by the surface acreage covering the anticipated productive Beluga 7 Formation sandstones. Since the Beluga reservoirs appear to be stacked sandstone bodies, the composite areas of the reservoir extent, which is controlled by structure and sandstone distribution and confirmed by seismic and well data, are summed together to define the outline of the BPA. 3) Prior Exploration Activities in the Nicolai Creek Unit The NCU was formed by Texaco on February 29, 1968 after discovering gas in the NCS- 1A and NCU-2 wells in 1966 and the NCU-3 well in 1967. NCS-1A produced an average 1.3 MMSCF/day of dry gas from December 1968 to February 1969 and NCU-2 produced an average of 0.4MMSCF/day of dry gas from October 1968 through November 1969. Upon completion of the aforementioned periods of productivity both NCS-1A and NCU-2 were shut-in. NCU-3, produced an average of 0.3 MMSCF/day dry gas from April 1969 through October 1977, when it was shut-in. During the period 1970 to 1988 three wells, NCU-4 (1970), NCU-5 (1972) and NCU-6 (1988) were drilled and they proved to be dry. In 1988, Unocal and Marathon acquired the field, each holding a 50% working interest. Unocal was designated the NCU operator. In 1991, Unocal worked over NCU-4 but failed to achieve commercial production. In 2000, Aurora took over the unit as operator with a 100% working interest. In 2000 and 2001, Aurora worked over NCU-3, sidetracked NCS-1A to the NCU-1B location, and repaired NCU-2. In 2001, Aurora installed production facilities and a pipeline for the NCU-3. It commenced production at an average rate of 1.1 MMSCF/D with an average of 35 barrels of water per day and continued to produce February 2004 when a workover to add additional perforations was completed. The well is currently shut-in but production is expected to be restored in 2005 at 0.5 to 1.0 MMSCF/D. In 2003, Aurora acquired a new 3-D seismic survey and drilled NCU-9 with a bottom-hole location between the two participating areas but outside of the NCU. Aurora also established new facilities and a pipeline to the SPA’s drill site in 2003. During 2003, Aurora produced gas from NCU-9 and NCU-2 at rates of 2.3 and 2.5 MMSCF/Day respectively. 4) The Applicant’s Plan for Development of the Participating Areas The Application included a revised Plan of Development (POD) for the NCU. The new POD is approved for the period beginning on the effective date of this Decision through December 31, 2005. The POD proposes extensive review and interpretation of existing 3D seismic data, which will 8 possibly lead to a new development well targeting the stacked Carya 2 (Upper Tyonek) channel sands. The unit operator also plans to reestablish production in the NCU-3 and continue production from NCU-2 and the NCU-9 wells. The NCU No. 1B well is currently shut-in pending further evaluation. Production rate is declining rapidly in the NCU-2, so Aurora plans to recomplete the well in the Tsuga 2-8.2 and 2-8.3 sands with the hopes of producing those intervals. The NCU-9 well produces from the Tsuga 2.8-1 sands, and Aurora plans additional recompletions in future years. NCU-3 produced sales gas between October 3, 2001 when the pipeline was installed, and February 2004, when the current work over program began. Aurora plans to commingle production of the deeper Tsuga 2-8.1 perforations with the shallower Carya 2-1.1, 2-1.2, and 2-2.1 in the NCU-3 well. 5) The Economic Costs and Benefits to the State Approval of the proposed BPA and associated field development will provide economic benefits to the state. The long-term goal is to maximize the physical and economic recovery of hydrocarbons from each of the productive reservoirs. Maximum hydrocarbon recovery will enhance the state’s long-term royalty and tax revenue stream. Any additional administrative burdens associated with the participating areas are far outweighed by the additional royalty and tax benefits derived from production. The Division finds Aurora’s tract allocation schedules acceptable for allocating production and costs among the leases in the participating areas. Aurora shall work with the Division’s Royalty Accounting Section to submit royalty and operator reports to properly allocate the production from the NCU-2 and NCU-9 wells to the SPA and BPA, back to November 1, 2003. Aurora shall submit revised royalty and operator reports for the NPA back to November 1, 2003 to correct inaccuracies in the reports. The production will be allocated based on the approved tract participation schedules for each participating area. Aurora must report production from the SPA, NPA, and BPA using production accounting unit codes NCPA, NCPB, and NCBE, respectively. IV. FINDINGS 1) Conservation of Natural Resources The formation of oil and gas units, as well as the formation of participating areas within units, generally conserves hydrocarbons. Coordinated development of leases held by diverse parties maximizes total hydrocarbon recovery and minimizes waste. Formation of the BPA will provide for efficient, integrated development of the Beluga reservoir within the NCU. A 9 comprehensive plan of development governing the area will help avoid duplicative development efforts on and beneath the surface. Producing hydrocarbon gas from the area through the NCU facility reduces the incremental environmental impact of the production. Creating the BPA will help maximize gas recovery, while minimizing negative impacts on all other natural resources. 2) Prevention of Economic and Physical Waste Generally, the formation of a participating area facilitates the equitable division of costs and allocation of the hydrocarbon shares, and provides for a diligent development plan, which helps to maximize hydrocarbon recovery from a reservoir. Further, the formation of a participating area, which enables both facility sharing opportunities and adoption of a unified reservoir management strategy, may allow economically marginal hydrocarbon accumulations to be developed. Formation of a participating area promotes complete development of a reservoir with variable productivity across adjoining leases. Commingling production from the Tyonek and Beluga Formations in the NPA will maximize drilling and completion efficiency and result in lower development costs, possibly extending the economic life of the field. 3) Protection of All Parties Because hydrocarbon recovery will more likely be maximized, the state’s economic interest is promoted. Diligent exploration and development under a single approved unit plan without the complications of competing leasehold interests promotes the state’s interest. The formation of the BPA advances the efficient evaluation and development of the state’s resources, while minimizing impacts to the area’s cultural, biological, and environmental resources. Operating under the NCU Agreement provides for accurate reporting and record keeping, and royalty settlement. These all protect the state’s interest. The proposed BPA and revised SPA protect the economic interests of the working interest owner and the royalty owners. V. DECISION Based on the facts discussed in this Decision and the administrative record, I make the following Findings and Decision: 1) The proposed acreage is underlain by hydrocarbons and known and reasonably estimated to be capable of production or contributing to production in sufficient quantities to justify the formation of the BPA, the revision of the SPA, and the revision of the NCU area. 10 2) The geological and engineering data justify the inclusion of the proposed acreage within the participating areas under the terms of the applicable regulations governing formation and operation of oil and gas units (11 AAC 83.301 – 11 AAC 83.395) and the terms and conditions under which these lands were leased from the state. 3) The Beluga Participating Area (BPA) is limited to the stratigraphic interval in the Beluga Formation encountered between 1320 and 1477 feet (measured depth) in NCU-9 (API 50-283-20102). 4) The Gas Pool PA-A, which is renamed the Southern Participating Area (SPA), is limited to the stratigraphic interval in the Tyonek Formation encountered between 2422 and 2918 feet (measured depth) in NCU-2 (API 50-283-10021). 5) The Gas Pool PA-B, which is renamed the Northern Participating Area (NPA), is limited to the stratigraphic interval in the Beluga and Tyonek Formations encountered between 1494 and 2238 feet (measured depth) in NCU-3 (API 50-283-20003). 6) Formation of the BPA and revision of the SPA provides for the equitable division of costs and an equitable allocation of produced hydrocarbons under a development plan designed to maximize physical and economic recovery from the reservoirs within the approved participating areas. 7) The allocations of production and costs for the tracts within the NCU participating areas (Exhibits B-1, B-2, and B-3), Attachments 5, 6, and 7 to this Findings and Decision are approved. 8) Approval of the formation of the BPA, revision to the SPA, revision to the NCU, and approval of the attached Exhibits to the NCU Agreement are retroactively effective to November 1, 2003. 9) Aurora shall report all production from the SPA, NPA, and BPA to Production Accounting Units NCPA, NCPB, and NCBE, respectively. 10) Aurora shall submit revised operator and royalty reports for accounting unit code NCPB from November 1, 2003 forward in order to correct inaccuracies in the reports. 11) Aurora shall submit separate original operator and royalty reports for accounting unit codes NCPA and NCBE from November 1, 2003 forward. Aurora shall also provide the royalty accounting section copies of all revised AOGCC reports (Form 10-422) from November 1, 2003 forward. For these reasons I hereby approve the formation of the Beluga Participating Area, the revision and renaming of the South Participating Area, the renaming of the North Participating Area, and the revision of the Nicolai Creek Unit area. Since the Application was approved by 11 the BLM on March 1, 2005 retroactively effective November 1, 2003, this Decision is also retroactively effective to November 1, 2003. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040 (c) and (d), and may be mailed or delivered to Thomas E. Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269-8918; or sent by electronic mail to dnr_appeals@dnr.state.ak.us. This decision takes effect immediately. If no appeal is filed by the appeal deadline, this decision becomes a final administrative order and decision of the department on the 31st day after issuance. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Signed on 03-14-2005 by Sean Parnell for Mark Myers 03/14/2005________ Mark D Myers Date Division of Oil and Gas Attachments: 1. Map of old and new NCU boundaries 2. Map of old and new SPA boundaries 3. Exhibit A to the NCU Agreement (Map of Unit and Participating Areas, 3 pages) 4. Exhibit B to the NCU Agreement (NCU Tract Schedule) 5. Exhibit B-1 to the NCU Agreement (Tract Participation Schedule for the North PA) 6. Exhibit B-2 to the NCU Agreement (Tract Participation Schedule for the South PA) 7. Exhibit B-3 to the NCU Agreement (Tract Participation Schedule for the Beluga PA) 8. Exhibit G to the NCU Agreement (Plan of Development) 9. AOGCC Conservation Order No. 478 10. AOGCC Conservation Order No. 478A 11. TLO letter commenting on the public notice 245 N AOGCC Nicolai Creek Field TOP TYONEK TIME STRUCTURE MAP REPRODUCED WITH OPERATOR PERMISSION MODIFIED FROM ORIGINAL SUBMITTAL BY AOGCC 0 3 miles Nicolai Creek Unit Boundary Cook Inlet Shoreline Well Trajectories 246 Knik ArmTurna g a i n A r m Seward Hwy H w y GlennSeward Hwy Sterling A la s k a R R A laskaR RHwy Parks Hwy SterlingHwyGulf of AlaskaC o o k I n l e tKachemak BayWasilla Tyonek Seward Palmer Ninilchik Nikiski Kenai Homer Cooper Landing Anchorage Houston Nicolai Creek Field Undef Gas Pool Nicolai Creek Field Steelhead Grayling Cook Inlet, Alaska DNR/DOG 2005 AAOrder No.DateOperator Description Current NICOLAI CREEK FIELD *No Pool* Current Orders 10 0AEO 06-Oct-04Envirotech LLC Order granting an aquifer exemption beginning at the ground surface for purposes of Class II disposal of treated, rpoduced water using a waste-water drain field installed at Envirotech's North Foreland Facility site. Y 24 0DIO 26-Jun-02AURORA GAS L Disposal of Class II oil field wastes by underground injection in the Tyonek Formation, Nicolai Creek Unit No. 5, Section 19, T11N, R12W, SM. Y 10 0OTH 14-Jan-02AURORA GAS L Approves the Nicolai Creek Field plan.Y 67 0CO 04-Oct-68TEXACO INC Because of unitization, sale of gas permitted field spacing order required by CO 028 no longer necessary. Y AAOrder No.DateOperator Description Current NICOLAI CREEK FIELD *No Pool* Spacing Exception Orders 478 0CO 05-Sep-02AURORA GAS L Spacing Exception to drill and test the Nicolai Creek Unit No. 1B and No. 8 wells and recomplete and test the No. 2 well. On 11/5/02 Nicolai Creek No. 9 permit to drill was approved. This conservation order governs Nicolai Creek 9. Y 28 0CO 23-Aug-66TEXACO INC Spacing exception for Nicolai Creek Unit #2.N 23 0CO TEXACO INC Request for spacing exception. Withdrawn.N AAOrder No.DateOperator Description Current NICOLAI CREEK FIELD NORTH UNDEFINED GAS POOL Current Orders 478 0ACO 16-Oct-03AURORA GAS L Order allowing regular production from Nicolai Creek Unit Wells No. 1B, No. 2 and No.9 in an undefined gas pool. 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EXHIBIT "A" Page 3 of 3 ~1 ~[D)\ JA~ P1 DIVI O'L~ SION OF,NO GASTRACT 2 CEE 1/64 CW1/16I AD!. C3 P2/ II ADl36736 WCMC- ~P7WCMC 1~ MEAN HKOH WATER UNE PER AD!. ~738 WCMC ADL C1 WCMCADLC4 P8 TRACT 4 7.903 AC ADL 17598 P9 P10 TRACT 3 P11 COOK INLET GR~PHIC 8:4400200 1000 (IN FEET) 1 inch = 400 It. SHEET: 2 of 3 .ORA"'" -."'"""'~I ~ ~Aurora Gas, LLC .PO ...,..~~~~~~~~~~on5Ulting C;rAJ!' ~C~ Te.sting ~",~~:1",~ ,-.c 7 ",. ...907 .~"",R&D- .,- --'to ,,- 27.550 AC I~DL 17585 NICOLAI SOUTH PATRACTS within Sec 29 and 30 T11 N R12W 8M AK ~~~~~v ~i5)~@ U\l JAN i;;= EXHIBIT "A" Page 2 of 3 1 2005 DIVIS OIL A~ ION OF~D GASI COOK INLET '-I~"~-- ~:,Aurora Gas, LLC Nicolai Nort PA, Nicolai South PA & Beluga P A racts ~~i~~V ,t 21 2005 )lON OF NO GA~ SHEET: 1 of 3.~-~ -I~I""II-~~- ~,Aurora Gas, LLC .""" ,., Findings and Decision of the Director of the Division of Oil and Gas APPROVAL OF THE REVISED NICOLAI CREEK UNIT AREA, REVISED PARTICIPATING AREAS A and B, AND FORMATION OF THE BELUGA PARTICIPATING AREA Under a Delegation of Authority from the Commissioner of the State Of Alaska Department of Natural Resources March 10, 2005 Table of Contents I. DECISION SUMMARY ........................................................ 2 II. BACKGROUND AND APPLICATION HISTORY ...................................... 2 III. PARTICIPATING AREA DECISION CRITERIA ................................... 5 IV. FINDINGS ................................................................ 8 V. DECISION ................................................................. 9 2 I. DECISION SUMMARY Aurora Gas, LLC (Aurora), as Nicolai Creek Unit (NCU) operator and sole working interest owner, applied to revise the existing participating areas, form the Beluga Participating Area, and revise the Nicolai Creek Unit Area (the Application). The State of Alaska Department of Natural Resources, Division of Oil and Gas (the DNR or the Division, as appropriate) approves the Application as follows: 1. Participating Area A is revised to reflect the current geologic and engineering interpretation for the reservoir and is renamed the South Participating Area (SPA). 2. Participating Area B is renamed the North Participating Area (NPA). 3. The new Beluga Participating Area (BPA) is approved. 4. A portion of federal lease AA-8426 is added to the NCU and the aerial extent of the Unit is revised to encompass the three PAs. As before, the unit area is limited to its approved participating areas. 5. Aurora shall work with the Division’s Royalty Accounting Section to revise all royalty and operator reports back to November 1, 2003. The production must be allocated based on the approved tract participation schedules for each participating area. Aurora submitted geologic and well data that indicate the revised SPA and proposed BPA are capable of producing or contributing to the production of hydrocarbons in paying quantities, which justifies revising the SPA and the NCU, and forming the BPA. Attachment 1 is a map showing the old and new NCU boundary. Attachment 2 is a map showing the old and new SPA boundary. Attachment 3 is Exhibit A to the NCU Agreement showing the approved boundaries for the NCU, BPA, SPA, and NPA. The Division also approves Exhibits B, B-1, B-2 and B-3 to the NCU Agreement (Attachments 4 through 7), the tract allocation schedules for each of the PAs. The tract allocation schedules equitably allocate production and costs among the leases in the NCU. II. BACKGROUND AND APPLICATION HISTORY Texaco formed the Nicolai Creek Unit and Participating Areas A and B in 1968. It drilled the Nicolai Creek State No. 1-A well (NCS-1A) in the Participating Area B and tested the well, but no facilities or pipelines were built to facilitate sustained production. It also drilled the Nicolai Creek No. 2 well (NCU-2) and the Nicolai Creek No. 3 well (NCU-3). NCU-2 tested gas from Participating Area A for nine months in 1968 and 1969. Facilities and a pipeline were installed for Participating Area B and NCU-3 produced from Participating area B from 1969 through 1977. 3 In 1973, the NCU boundary contracted to the discontiguous lands within Participating Areas A and B. Unocal and Marathon acquired the field in 1988, each holding 50% working interest, and Unocal was the designated unit operator. Beginning in 1998, AS 38.05.180(f)(5) provided for a temporary royalty reduction to encourage development of certain fields in the Cook Inlet Basin, including Nicolai Creek. The Statute establishes a royalty rate of five percent on the first 25,000,000 barrels of oil and 35,000,000,000 cubic feet of gas produced from eligible fields within 10 years of initial production for sale, if production for sale commenced before January 1, 2004. To qualify for the reduced royalty rate on production from the Nicolai Creek Field, the operator was required to submit a written plan to the Alaska Oil and Gas Conservation Commission (AOGCC) in accordance with AS 31.05.030(i). This generous economic incentive was intended to encourage Unocal to bring the Nicolai Creek Unit on production earlier than planned. In November 2000, Unocal and Marathon assigned their interests to Aurora. Aurora became the operator with 100 percent working interest in the NCU. Aurora successfully restarted sustained production in the NCU-3 well in September 2001 and the AOGCC approved its written plan submitted under AS 31.05.030(i), which qualified the field for the royalty reduction. By letter date July 12, 2002, Aurora requested an order from the AOGCC allowing a spacing exception to drill and test the Nicolai Creek Unit No. 1B (NCU-1B) and No. 8 (NCU-8) wells and to recomplete and test the NCU-2 well. The AOGCC issued Conservation Order No. 478 (Attachment 9), on September 5, 2002, which approved Aurora’s request for spacing exceptions but provided that the wells could not be placed on regular production until the AOGCC took additional action to offset any advantage Aurora may have had over other mineral owners by reason of the wells having been drilled to the exception locations. Aurora did not drill the NCU-8 well because it encountered a shallow obstruction while driving conductor pipe, but permitted and drilled NCU No. 9 (NCU-9) as a replacement well. On September 2, 2003, Aurora submitted an application to the Division for approval to revise the participating areas and the NCU boundary. The Division immediately notified Aurora that its application was incomplete and began working with Aurora to remedy the deficiencies. It quickly became apparent that the process was going to take an extended period of time due to the number of parties involved, and the unresolved land ownership and title issues. The Division invited the Mental Health Trust Land Office (TLO) to participate in all pertinent Application communications, discussions, and meetings between Aurora and the Division because they are an adjacent mineral interest owner. As early as August 12, 2003, the Division’s goal was to include the TLO throughout the process and arrive at a fair decision that the TLO would support. In the interim, Aurora proposed to report production from the NCU-1B and NCU-2 wells to the Division at a five percent royalty rate, and production from the NCU-9 to the Bureau of 4 Land Management (BLM) using a 12.5 percent royalty rate. On September 25, 2003, the Division, the TLO and BLM agreed with this interim royalty reporting payment methodology, on condition that, upon approval of the final Application, Aurora shall submit revised royalty and operator reports to the Division and BLM retroactive to the first day of production (See Attachment 12). On October 9, 2003, Aurora submitted a revised Application, to the Division, along with additional supporting confidential geologic and engineering data. On October 16, 2003, the AOGCC issued Conservation Order No. 478A (Attachment 10) allowing regular production from the NCU-1B, NCU-2 and NCU-9 wells using the interim reporting methodology. In November 2003, Aurora completed pipeline and facility construction for PA-B and initiated production from the NCU-2 and NCU-9 wells. The Division worked with Aurora, the BLM and the TLO on the Application, and on November 4, 2003, the Division determined that the Application included all of the items listed in 11 AAC 83.306 and constituted a complete application for public notice. The Division issued a public notice of the Revised Application on November 5, 2003, which DNR posted on the State’s web page. The notice was published in the Anchorage Daily News and the Peninsula Clarion on Sunday, November 9, 2003. The public notice invited interested parties and members of the public to submit comments on the Application by December 9, 2003. The Division received two comment letters in response to the pubic notice. The first letter, submitted by the TLO to document its involvement in the process of approving the Application, is attached to this Decision (Attachment 11). The second letter was from the Kenai Peninsula Borough, which reviewed the proposed unit expansion for consistency with the Kenai Peninsula Borough Coastal Management Program enforceable policies. The Kenai Peninsula Borough had no objection to approval of the Application. On January 7, 2004, Aurora submitted a request to suspend the Application process until such time that the technical details could be resolved. On January 8, 2004, the Division approved the suspension of the Application and encouraged Aurora to continue working with the interested parties to reach agreement on the revised unit and participating area boundaries. After working with the various parties, on and off for approximately one year, on January 21, 2005, Aurora submitted a final, revised Application that included new tract participation schedules and a proposal to create an additional participating area (BPA). The Application proposes to include a portion of federal lease AA-8426, approximately 45.30 acres, in the NCU. Aurora is the only working interest owner, but there are approximately 16 overriding royalty owners. There is geologic and engineering evidence to support the formation of the BPA to develop 5 the Beluga Reservoirs within the revised NCU. The data also supports revising the SPA to develop the Tyonek Reservoirs under a unified plan of development. III. PARTICIPATING AREA DECISION CRITERIA AS 38.05.180(p) gives DNR the authority to approve an oil and gas unit. The DNR Commissioner (Commissioner) reviews unit and participating area applications under AS 38.05.180(p) and 11 AAC 83.301 – 11 AAC 83.395. By memorandum dated September 30, 1999, the Commissioner approved a revision of Department Order 003, and delegated this authority to the Division Director (Director). Under 11 AAC 83.303(a), the Director will approve the Application upon finding that it will: 1) promote the conservation of all natural resources; 2) promote the prevention of economic and physical waste; and 3) provide for the protection of all parties of interest, including the state. Subsection .303(b) sets out six criteria that the Director will consider in evaluating the Application. A discussion of the subsection .303(b) criteria, as they apply to the Application, is set out directly below, followed by the Director’s findings relevant to subsection .303(a) and the Director’s conditional approval of the Application. A participating area may include only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. 11 AAC 83.351(a). “Paying Quantities” means: Quantities sufficient to yield a return in excess of operating, costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are sufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. 11 AAC 83.395(4) 1) The Environmental Costs and Benefits Approval of the BPA and the revision of the SPA has no environmental impact. This Decision is an administrative action and does not authorize any surface activity. Potential effects on the environment are analyzed when permits to conduct exploration or development in the unit area are reviewed. In fact, unitized development has less impact on the environment than development on a lease-by-lease basis. 2) The Geological and Engineering Characteristics of the Proposed PAs The State’s regulations provide that a unit must encompass the minimum area required to include all or part of one or more oil or gas reservoirs, or potential accumulations. 11 AAC 83.356(a). DNR technical staff evaluated all data provided by the unit operator including 6 geologic cross sections, structure maps, electric log analyses, and interpreted seismic data to determine if the proposed unit area met the regulatory criteria. The reservoir sandstones of the NCU belong to the Oligo/Miocene Tyonek and Beluga Formations. Only those sands of the Tyonek Formation are currently producing. Deposition of these sands occurred within the Cook Inlet Basin, a feature characterized as an elongate, northeast trending, fault-bounded forearc basin that extends from the Matanuska Valley south along the Alaska Peninsula. The northwestern reaches of the Cook Inlet forearc basin are defined by a series of tight anticlines and associated structures that deform the Tertiary section and provide traps for both oil and gas. These features are part of a transpressional regime that results from strain transfer between the Castle Mountain Fault to the north and Bruin Bay Fault to the west. The structures manifested within the NCU have evolved through such processes. Subsurface geology of the NPA of the NCU indicates a combination structural and stratigraphic trap with gas trapped in Upper Tyonek sandstones. Sandstone units are draped over a four-way closure anticline formed along a southward-plunging axis on the west side of an eastward-verging fault (interpreted to be the northern extension of the Trading Bay fault). A similar setting exists in the subsurface of the SPA of Upper Tyonek gas bearing sandstones trapped within a fold and closed against a dominant west-east cross-fault (the Nicolai Cross Fault) that splays off the aforementioned Trading Bay Fault to the east. The Nicolai Cross Fault appears to separate the structure of the NPA from that of the SPA. From a maximum of approximately 500-600 feet in the east, the fault throw diminishes westwards. Within the NPA and SPA, reservoirs sandstones are restricted to the Upper Tyonek Formation. Eight individual sand members have been identified from log correlation and mapped across the Nicolai Creek field. Within the Nicolai Creek field, individual sands have been assigned names based on standardized industry palynological zonation. The sandstones are within the Carya 2 palynological zone and have been subdivided using an appropriate numeric designation (2-1.1, 2-1.2, 2-2.1, 2-2.2, 2-2.3, 2-4.2, 2-5.1, and 2-6.1). Log data indicate the NCU wells show the relative conformity of the shallower Carya 2-1 through Carya 2-23 section with some possible expansion of the deeper Carya 2-4.2 through Carya 2-6.1 section. The apparent expansion of the deeper section in the NCU-2 well could be explained by faulting. Gas appears trapped in the Upper Tyonek Formation in unconsolidated, non-marine sandstone reservoirs between 1,680 and 3,475 feet subsea true vertical depth (SSTVD). Since the Tyonek reservoirs of both the NPA and SPA are stacked sandstone bodies, the composite areas of the reservoir extent, which is controlled by structure and sandstone distribution and confirmed by seismic and well data, are summed together to define the outline of the SPA and NPA areas. The BPA is defined by the surface acreage covering the anticipated productive Beluga 7 Formation sandstones. Since the Beluga reservoirs appear to be stacked sandstone bodies, the composite areas of the reservoir extent, which is controlled by structure and sandstone distribution and confirmed by seismic and well data, are summed together to define the outline of the BPA. 3) Prior Exploration Activities in the Nicolai Creek Unit The NCU was formed by Texaco on February 29, 1968 after discovering gas in the NCS- 1A and NCU-2 wells in 1966 and the NCU-3 well in 1967. NCS-1A produced an average 1.3 MMSCF/day of dry gas from December 1968 to February 1969 and NCU-2 produced an average of 0.4MMSCF/day of dry gas from October 1968 through November 1969. Upon completion of the aforementioned periods of productivity both NCS-1A and NCU-2 were shut-in. NCU-3, produced an average of 0.3 MMSCF/day dry gas from April 1969 through October 1977, when it was shut-in. During the period 1970 to 1988 three wells, NCU-4 (1970), NCU-5 (1972) and NCU-6 (1988) were drilled and they proved to be dry. In 1988, Unocal and Marathon acquired the field, each holding a 50% working interest. Unocal was designated the NCU operator. In 1991, Unocal worked over NCU-4 but failed to achieve commercial production. In 2000, Aurora took over the unit as operator with a 100% working interest. In 2000 and 2001, Aurora worked over NCU-3, sidetracked NCS-1A to the NCU-1B location, and repaired NCU-2. In 2001, Aurora installed production facilities and a pipeline for the NCU-3. It commenced production at an average rate of 1.1 MMSCF/D with an average of 35 barrels of water per day and continued to produce February 2004 when a workover to add additional perforations was completed. The well is currently shut-in but production is expected to be restored in 2005 at 0.5 to 1.0 MMSCF/D. In 2003, Aurora acquired a new 3-D seismic survey and drilled NCU-9 with a bottom-hole location between the two participating areas but outside of the NCU. Aurora also established new facilities and a pipeline to the SPA’s drill site in 2003. During 2003, Aurora produced gas from NCU-9 and NCU-2 at rates of 2.3 and 2.5 MMSCF/Day respectively. 4) The Applicant’s Plan for Development of the Participating Areas The Application included a revised Plan of Development (POD) for the NCU. The new POD is approved for the period beginning on the effective date of this Decision through December 31, 2005. The POD proposes extensive review and interpretation of existing 3D seismic data, which will 8 possibly lead to a new development well targeting the stacked Carya 2 (Upper Tyonek) channel sands. The unit operator also plans to reestablish production in the NCU-3 and continue production from NCU-2 and the NCU-9 wells. The NCU No. 1B well is currently shut-in pending further evaluation. Production rate is declining rapidly in the NCU-2, so Aurora plans to recomplete the well in the Tsuga 2-8.2 and 2-8.3 sands with the hopes of producing those intervals. The NCU-9 well produces from the Tsuga 2.8-1 sands, and Aurora plans additional recompletions in future years. NCU-3 produced sales gas between October 3, 2001 when the pipeline was installed, and February 2004, when the current work over program began. Aurora plans to commingle production of the deeper Tsuga 2-8.1 perforations with the shallower Carya 2-1.1, 2-1.2, and 2-2.1 in the NCU-3 well. 5) The Economic Costs and Benefits to the State Approval of the proposed BPA and associated field development will provide economic benefits to the state. The long-term goal is to maximize the physical and economic recovery of hydrocarbons from each of the productive reservoirs. Maximum hydrocarbon recovery will enhance the state’s long-term royalty and tax revenue stream. Any additional administrative burdens associated with the participating areas are far outweighed by the additional royalty and tax benefits derived from production. The Division finds Aurora’s tract allocation schedules acceptable for allocating production and costs among the leases in the participating areas. Aurora shall work with the Division’s Royalty Accounting Section to submit royalty and operator reports to properly allocate the production from the NCU-2 and NCU-9 wells to the SPA and BPA, back to November 1, 2003. Aurora shall submit revised royalty and operator reports for the NPA back to November 1, 2003 to correct inaccuracies in the reports. The production will be allocated based on the approved tract participation schedules for each participating area. Aurora must report production from the SPA, NPA, and BPA using production accounting unit codes NCPA, NCPB, and NCBE, respectively. IV. FINDINGS 1) Conservation of Natural Resources The formation of oil and gas units, as well as the formation of participating areas within units, generally conserves hydrocarbons. Coordinated development of leases held by diverse parties maximizes total hydrocarbon recovery and minimizes waste. Formation of the BPA will provide for efficient, integrated development of the Beluga reservoir within the NCU. A 9 comprehensive plan of development governing the area will help avoid duplicative development efforts on and beneath the surface. Producing hydrocarbon gas from the area through the NCU facility reduces the incremental environmental impact of the production. Creating the BPA will help maximize gas recovery, while minimizing negative impacts on all other natural resources. 2) Prevention of Economic and Physical Waste Generally, the formation of a participating area facilitates the equitable division of costs and allocation of the hydrocarbon shares, and provides for a diligent development plan, which helps to maximize hydrocarbon recovery from a reservoir. Further, the formation of a participating area, which enables both facility sharing opportunities and adoption of a unified reservoir management strategy, may allow economically marginal hydrocarbon accumulations to be developed. Formation of a participating area promotes complete development of a reservoir with variable productivity across adjoining leases. Commingling production from the Tyonek and Beluga Formations in the NPA will maximize drilling and completion efficiency and result in lower development costs, possibly extending the economic life of the field. 3) Protection of All Parties Because hydrocarbon recovery will more likely be maximized, the state’s economic interest is promoted. Diligent exploration and development under a single approved unit plan without the complications of competing leasehold interests promotes the state’s interest. The formation of the BPA advances the efficient evaluation and development of the state’s resources, while minimizing impacts to the area’s cultural, biological, and environmental resources. Operating under the NCU Agreement provides for accurate reporting and record keeping, and royalty settlement. These all protect the state’s interest. The proposed BPA and revised SPA protect the economic interests of the working interest owner and the royalty owners. V. DECISION Based on the facts discussed in this Decision and the administrative record, I make the following Findings and Decision: 1) The proposed acreage is underlain by hydrocarbons and known and reasonably estimated to be capable of production or contributing to production in sufficient quantities to justify the formation of the BPA, the revision of the SPA, and the revision of the NCU area. 10 2) The geological and engineering data justify the inclusion of the proposed acreage within the participating areas under the terms of the applicable regulations governing formation and operation of oil and gas units (11 AAC 83.301 – 11 AAC 83.395) and the terms and conditions under which these lands were leased from the state. 3) The Beluga Participating Area (BPA) is limited to the stratigraphic interval in the Beluga Formation encountered between 1320 and 1477 feet (measured depth) in NCU-9 (API 50-283-20102). 4) The Gas Pool PA-A, which is renamed the Southern Participating Area (SPA), is limited to the stratigraphic interval in the Tyonek Formation encountered between 2422 and 2918 feet (measured depth) in NCU-2 (API 50-283-10021). 5) The Gas Pool PA-B, which is renamed the Northern Participating Area (NPA), is limited to the stratigraphic interval in the Beluga and Tyonek Formations encountered between 1494 and 2238 feet (measured depth) in NCU-3 (API 50-283-20003). 6) Formation of the BPA and revision of the SPA provides for the equitable division of costs and an equitable allocation of produced hydrocarbons under a development plan designed to maximize physical and economic recovery from the reservoirs within the approved participating areas. 7) The allocations of production and costs for the tracts within the NCU participating areas (Exhibits B-1, B-2, and B-3), Attachments 5, 6, and 7 to this Findings and Decision are approved. 8) Approval of the formation of the BPA, revision to the SPA, revision to the NCU, and approval of the attached Exhibits to the NCU Agreement are retroactively effective to November 1, 2003. 9) Aurora shall report all production from the SPA, NPA, and BPA to Production Accounting Units NCPA, NCPB, and NCBE, respectively. 10) Aurora shall submit revised operator and royalty reports for accounting unit code NCPB from November 1, 2003 forward in order to correct inaccuracies in the reports. 11) Aurora shall submit separate original operator and royalty reports for accounting unit codes NCPA and NCBE from November 1, 2003 forward. Aurora shall also provide the royalty accounting section copies of all revised AOGCC reports (Form 10-422) from November 1, 2003 forward. For these reasons I hereby approve the formation of the Beluga Participating Area, the revision and renaming of the South Participating Area, the renaming of the North Participating Area, and the revision of the Nicolai Creek Unit area. Since the Application was approved by 11 the BLM on March 1, 2005 retroactively effective November 1, 2003, this Decision is also retroactively effective to November 1, 2003. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040 (c) and (d), and may be mailed or delivered to Thomas E. Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269-8918; or sent by electronic mail to dnr_appeals@dnr.state.ak.us. This decision takes effect immediately. If no appeal is filed by the appeal deadline, this decision becomes a final administrative order and decision of the department on the 31st day after issuance. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Signed on 03-14-2005 by Sean Parnell for Mark Myers 03/14/2005________ Mark D Myers Date Division of Oil and Gas Attachments: 1. Map of old and new NCU boundaries 2. Map of old and new SPA boundaries 3. Exhibit A to the NCU Agreement (Map of Unit and Participating Areas, 3 pages) 4. Exhibit B to the NCU Agreement (NCU Tract Schedule) 5. Exhibit B-1 to the NCU Agreement (Tract Participation Schedule for the North PA) 6. Exhibit B-2 to the NCU Agreement (Tract Participation Schedule for the South PA) 7. Exhibit B-3 to the NCU Agreement (Tract Participation Schedule for the Beluga PA) 8. Exhibit G to the NCU Agreement (Plan of Development) 9. AOGCC Conservation Order No. 478 10. AOGCC Conservation Order No. 478A 11. TLO letter commenting on the public notice