Document:

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                                                                 EXHIBIT 10.22.2

[LASALLE BANK LOGO]                                  LASALLE BANK MIDWEST N.A.
                                                     2600 West Big Beaver Road
                                                     Mailcode M0900-290
                                                     Troy, MI 48084
                                                     (248) 822-5683
                                                     Fax: (248) 822-5748
                                                     gregory.castle@abnamro.com
                               February 15, 2006

                                                     GREGORY E. CASTLE
                                                     First Vice President

                                                     MIDDLE MARKET BANKING
SEMCO Energy, Inc.

      Re:   Second Amended and Restated Credit Agreement dated as of September
            15, 2005 by and among the financial institutions from time to time
            signatory thereto (each a "Lender", and collectively the "Lenders"),
            LaSalle Bank Midwest National Association, as Administrative Agent
            for the Lenders (in such capacity, "Agent"), and SEMCO Energy, Inc.
            ("Company"), as amended from time to time prior to the date hereof
            (the "Credit Agreement").

      Ladies and Gentlemen:

      Reference is made to the Credit Agreement. Except as specifically defined
to the contrary herein, capitalized terms used herein shall have the meanings
given them in the Credit Agreement.

      Per Section 4.1(c) of the Credit Agreement, you previously requested that
we make Swing Line Loans available to you at an interest rate equal to our
one-week LIBOR rate plus the LIBOR Margin in effect from time to time as stated
in the Credit Agreement (the "New Negotiated Rate"). We agreed to your request
for the period commencing January 31, 2006 through and including May 31, 2006.

      In connection with our extending to you the New Negotiated Rate, we ask
that you acknowledge via execution of the signature block provided below: (i)
that the Swing Line Loans shall bear interest at the New Negotiated Rate for the
period set forth above and (ii) that all of the other terms, conditions and
requirements regarding the Swing Line and the Swing Line Loans as set forth in
the Credit Agreement remain in effect, unchanged.

                                        Very truly yours,

                                        LASALLE BANK MIDWEST NATIONAL
                                        ASSOCIATION, as Swing Line Lender

                                        By /s/ Gregory E. Castle
                                           ------------------------------------

                                        Its: FIRST VICE PRESIDENT

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                                        Acknowledged and agreed:

                                        SEMCO ENERGY, INC.

                                        By: /s/ Michael V. Palmeri
                                            -----------------------------------

                                        Its: EVP and CFO

                                        Date: Feb. 15, 2006

                                       2<PAGE>

                                                                   EXHIBIT 10.24

                               GAS SALES AGREEMENT

                                     BETWEEN

                        UNION OIL COMPANY OF CALIFORNIA

                                       AND

                            ALASKA PIPELINE COMPANY

                                                EFFECTIVE DATE NOVEMBER 17, 2000

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                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                                       PAGE
                                                                                                       ----
<S>                                                                                                    <C>
Article I - Definitions.............................................................................      2

Article II - Seller's Exploration and Development Commitment........................................      8

        2.1 Exploration Commitment..................................................................      8

        2.2 Exploration Area........................................................................      9

        2.3 Material Consideration..................................................................     10

Article III - Sale and Purchase of Gas..............................................................     10

        3.1 Quantity................................................................................     10

        3.2 Initial Commitment......................................................................     10

        3.3 Additional Unocal Commitments...........................................................     10

        3.4 Gas Balancing...........................................................................     17

        3.5 Unanticipated Shortages.................................................................     19

        3.6 Gas Production Not Economic.............................................................     19

        3.7 Quantity Calculation Example............................................................     20

        3.8 Title and Risk of Loss..................................................................     20

        3.9 Operational Communications..............................................................     21

Article IV - Price and Transportation Fee...........................................................     21

        4.1 Gas Price...............................................................................     21

        4.2 References..............................................................................     22

        4.3 Calculation.............................................................................     22
</TABLE>

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<TABLE>
<S>                                                                                                    <C>

        4.4 No Determination.......................................................................      23

        4.5 Transportation Fee......................................................................     23

        4.6 Peaking Gas Fee.........................................................................     24

        4.7 Price Example...........................................................................     24

Article V - Term....................................................................................     24

Article VI - Taxes..................................................................................     24

        6.1 General Allocation......................................................................     24

        6.2 Specific Allocation.....................................................................     24

        6.3 New Taxes...............................................................................     25

        6.4 Production Tax Adjustment...............................................................     25

Article VII - Royalties.............................................................................     25

Article VIII - Reserved for Future Use..............................................................     26

Article IX - Quality................................................................................     26

        9.1 Heating Value of Gas....................................................................     26

        9.2 Deleterious Matter Specification........................................................     26

        9.3 Filtration of Gas.......................................................................     27

        9.4 Buyer's Right to Refuse Gas.............................................................     27

Article X - Pressure, Measurement, Metering, Testing................................................     28

        10.1 Pressure...............................................................................     28

        10.2 Measurement............................................................................     28

        10.3 Inaccurate Meters......................................................................     28

        10.4 Testing................................................................................     29

        10.5 Correction.............................................................................     29

        10.6 Records................................................................................     30
</TABLE>

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<TABLE>
<S>                                                                                                    <C>
        10.7 Standards..............................................................................     30

        10.8 Check Meters...........................................................................     31

Article XI - Billing, Payment and Records...........................................................     31

        11.1 Billing................................................................................     31

        11.2 Records................................................................................     32

        11.3 Interest...............................................................................     32

Article XII - RCA Approval and DNR Agreement........................................................     33

        12.1 RCA Approval...........................................................................     33

        12.2 DNR Agreement..........................................................................     33

Article XIII - Boiler Plate.........................................................................     34

        13.1 Force Majeure..........................................................................     34

        13.2 Binding on Successors..................................................................     37

        13.3 Assignments and Other Transfers........................................................     37

        13.4 Easements and Rights-of-Way............................................................     37

        13.5 Governing Law..........................................................................     37

        13.6 Agreement Not to be Construed Against Either Party as Drafter..........................     38

        13.7 Notices................................................................................     38

        13.8 Entire Agreement.......................................................................     40

        13.9 Headings...............................................................................     41

        13.10 No Incidental or Consequential Damages................................................     41

        13.11 Termination Events....................................................................     41

        13.12 Waiver ...............................................................................     42

        13.13 Multiple Originals....................................................................     42

        13.14 Fees and Costs........................................................................     42
</TABLE>

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<TABLE>
<S>                                                                                                    <C>
        13.15 Authority to Sign.....................................................................     43

        13.16 Further Assurances....................................................................     43

Exhibit A      Buyer's Existing Commitments.........................................................     44

Exhibit B      Quantity Calculation Examples........................................................     46

Exhibit C      Buyer's Ten Year Forecast............................................................     52

Exhibit D      Form of Seller's Commitment..........................................................     54

Exhibit E      Seller's Existing Commitments........................................................     56

Exhibit F      Price Calculation Example............................................................     57

Exhibit G      Receipt Point(s).....................................................................     61
</TABLE>

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                               GAS SALES AGREEMENT

      This Gas Sales Agreement ("Agreement") is between Union Oil Company of
California ("Seller"), a California corporation, and Alaska Pipeline Company
("Buyer"), an Alaska corporation and wholly-owned subsidiary of SEMCO Energy,
Inc.

                                     RECITAL

      1. Buyer is a public utility that holds Certificate No. 141 from the
Regulatory Commission of Alaska ("RCA");

      2. Buyer, and its public utility affiliate ENSTAR Natural Gas Company,
provide natural gas service to the Municipality of Anchorage, and portions of
the Matanuska-Susitna and Kenai Peninsula Boroughs;

      3. Buyer plans to purchase additional Gas to meet the needs of ENSTAR's
customers;

      4. Buyer believes it is in the best interest of its customers to encourage
exploration for, development of, and delivery of new Gas into the Cook Inlet
area;

      5. Seller is willing to commit to exploration for and development of new
Gas in the Cook Inlet area, and to continue development as provided in Article
II;

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      6. Seller wishes to sell Gas to Buyer if Seller develops Gas in quantities
that can be produced economically;

      7. An agreement for the sale of Gas is necessary before Seller incurs
additional exploration and development costs;

      8. The RCA must have adequate time to review and approve this Agreement;

      9. DNR must have adequate time to consider the action requested of it
under this Agreement, and;

      10. Buyer wishes to have Seller's Gas committed to Buyer as quickly as
possible.

      In consideration of all the conditions in this Agreement, Buyer and Seller
agree as follows:

                                    ARTICLE I
                                  DEFINITIONS

      "Additional Third-Party Commitment" means a contract (including an
amendment after the Effective Date of a contract listed on Exhibit A) for Buyer
to purchase Gas from a third party. Contracts listed in Exhibit A, as amended
through the Effective Date, are not Additional Third Party Commitments.

      "Additional Unocal Commitments" is defined in paragraph 3.3.2.

      "Agreement" means this document and the attached exhibits as originally
executed, amended, supplemented, or assigned.

                                       2
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      "Annual Purchase Obligation" means the amount of Gas Buyer is obligated to
purchase and Seller is obligated to sell and deliver to Buyer each Year. Buyer
is not required to purchase in any Year more Gas than the difference between
Requirements and the sum of Buyer's Existing Commitments and any Additional
Third Party Commitments.

      "Balancing Gas" is defined in Section 3.4.

      "BTU; MMBTU": "BTU" means a British thermal unit. A British thermal unit
is the amount of energy required to raise the temperature of one pound of pure
water from fifty-nine degrees Fahrenheit (59(degree) F.) to sixty degrees
Fahrenheit (60(degree) F.) at a constant pressure of 14.73 pounds per square
inch absolute. "MMBTU" means one million (1,000,000) BTU.

      "Buyer's Existing Commitments" means the Gas Buyer is contractually
obligated to purchase each Year from third parties under the contracts listed in
Exhibit A.

      "Buyer's Forecast" is defined in paragraph 3.3.1.

      "Commitment Date" and "Commitment Period" are defined in paragraph 3.3.3.

      "Day" means a period beginning at eight o'clock a.m. (8:00 a.m.), Alaska
Standard Time, on a calendar day and ending at eight o'clock a.m. (8:00 a.m.),
Alaska Standard Time, on the next calendar day.

      "Deliverability" means the maximum amount of Gas that Seller is obligated
to deliver each Day. Seller is not obligated to be able to deliver Gas at a rate
that,

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if sustained for a Day, would result in deliveries greater than the
Deliverability for that Day determined under Article III. Deliverability is
expressed as MMcf per Day.

      "DNR" means the Department of Natural Resources, Division of Oil and Gas,
of the State of Alaska.

      "Economic" is defined in Section 3.6.

      "Effective Date" is defined in Article V.

      "Engineer" means an independent, registered professional petroleum
engineer from the firm of DeGolyer and McNaughton of Dallas, Texas, the firm of
Ryder Scott Company of Houston, Texas, or from another firm agreed to by Buyer
and Seller. The Engineer's fees and expenses shall be paid by Seller.

      "ENSTAR" means the natural gas distribution utility named ENSTAR Natural
Gas Company, a division of SEMCO Energy, Inc. ENSTAR holds RCA Certificate No.
4. ENSTAR and Buyer are regulated as a single entity by the RCA.

      "Exchange Agreement" means an agreement to exchange Gas at one receipt
point for Gas at another receipt point when the deliveries at the two receipt
points occur at approximately the same time

      "Force Majeure" and "Force Majeure Event" are defined in Article XIII.

      "Gas" means natural gas, including both gas well gas and oil well gas of
the quality described in Article IX.

                                       4
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      "Gross Heating Value" means the total calorific value, expressed in BTUs,
obtained by the complete combustion, at constant pressure, of one Standard Cubic
Foot of Gas, with air of the same temperature and pressure as the Gas, when the
products of combustion are cooled to the initial temperature of the Gas and air
and when the water formed by combustion is condensed to the liquid state.

      "Initial Commitment" means the quantity of Gas that will be delivered in
accordance with paragraph 3.2. The Initial Commitment is part of the Annual
Purchase Obligation.

      "LNG" means liquefied Gas.

      "Maximum Deliverability" means the total amount of Gas (from all
suppliers) that Buyer needs on the peak Day (expressed as MMcf per Day).

      "Mcf; MMcf; Bcf": "Mcf" means one thousand (1,000) Standard Cubic Feet;
"MMcf" means one million (1,000,000) Standard Cubic Feet; and "Bcf" means one
billion (1,000,000,000) Standard Cubic Feet.

      "Month" means a period beginning at eight o'clock a.m. (8:00 a.m.), Alaska
Standard Time, on the first day of a calendar month and ending at eight o'clock
a.m. (8:00 a.m.), Alaska Standard Time, on the first day of the next calendar
month.

      "Parties" means, collectively, Buyer and Seller.

      "Party" means Buyer and Seller, individually.

      "Peaking Gas Fee" is defined in Section 4.6.

                                       5
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      "Pipeline System" means Buyer and ENSTAR's entire, interconnected system
of transmission and distribution pipelines. A customer who is not connected to
the interconnected system is not served by the Pipeline System. For example, a
customer served by a satellite LNG system is not connected to the Pipeline
System because that customer is not connected to the interconnected system.

      "Price" is defined in Section 4.1.

      "Production Taxes" means the tax defined and set by AS 43.55.016, as
amended from time to time.

      "Pro Rata Share of Maximum Deliverability" means, for any Year, the
Maximum Deliverability multiplied by a fraction, the numerator of which is the
amount of Gas Seller has committed to supply for that Year and the denominator
of which is Buyer's Requirements for that Year. The values for the numerator and
denominator shall be taken from the current Buyer's Forecast for that Year.

      "Pro Rata Share of Total Daily Deliverability" means, for any Day, the
Total Daily Deliverability for that Day multiplied by a fraction, the numerator
of which is the amount of Gas Seller has committed to supply for that Year and
the denominator of which is Buyer's Requirements for that Year. The values for
the numerator and denominator shall be taken from the current Buyer's Forecast
for that Year.

      "RCA" means the Regulatory Commission of Alaska.

                                       6
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      "Receipt Points" means the metering points where Buyer receives Seller's
Gas into its Pipeline System and title passes. The Receipt Points are described
in Exhibit G. By mutual agreement, the Parties may amend Exhibit G to add,
delete, or modify Receipt Points.

      "Requirements" means all of the Gas that Buyer purchases, consumes, or
uses to supply ENSTAR customers who are served by connections to the Pipeline
System. "Requirements" does not include (i) Gas purchased, consumed, or used by
ENSTAR's customers who are not connected to the Pipeline System, or (ii) Gas
transported by Buyer for third parties under transportation agreements or
tariffs, or exchanged under Exchange Agreements. "Requirements" also does not
include Storage Gas purchased by Buyer to meet deliverability needs in excess of
Deliverability supplied by Seller.

      "Seller's Commitment" is defined in paragraph 3.3.2. and will be in the
form shown in Exhibit D.

      "Seller's Deliverability Forecast" is defined in paragraph 3.3.4(vii).

      "Standard Cubic Foot" means the amount of Gas that would occupy a volume
of one cubic foot at a temperature of sixty degrees Fahrenheit (60(degree) F.)
and at a pressure of fourteen and sixty-five hundredths (14.65) pounds per
square inch absolute.

      "Seller's Existing Commitments" means the Gas that Seller is contractually
obligated to sell each Year to third parties under the contracts listed in
Exhibit E.

                                       7
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      "Storage Gas" means Gas acquired from a third party to put into storage
(including Gas purchased or stored as LNG) or Gas taken from storage.

      "Swing Rate" means the ratio of the Deliverability (MMcf per Day) to the
annual purchases expressed as a daily average (MMcf/Day). For example, if annual
purchases were 2.92 Bcf and Deliverability were 20 MMcf per Day, the Swing Rate
would be [20 / (2920 / 365)] = 2.5.

      "Termination Event" is defined in Section 13.11.

      "Total Daily Deliverability" means the total amount of Gas (from all
suppliers) that Buyer needs on any Day (expressed as MMcf per Day).

      "Transportation Fee" is defined in Section 4.5.

      "Unmet Requirements" means the difference between Requirements for any
Year and the sum of Buyer's Existing Commitments for that Year, Additional
Third-Party Commitments for that Year, and Unocal's Initial and Additional
Commitments for that Year.

      "Year" means a period of twelve (12) consecutive Months beginning on
January 1 and ending on the next January 1.

                                   ARTICLE II
                 SELLER'S EXPLORATION AND DEVELOPMENT COMMITMENT

      2.1 EXPLORATION COMMITMENT: Buyer and Seller believe that there have been
only modest discoveries of natural gas in the Cook Inlet area in the past thirty
years. DNR records show that during that time gas supply available to the area
has decreased from a 60-year supply to approximately a ten-year supply. Because

                                       8
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of sharp seasonal fluctuations in demand caused by cold winter weather, the
Parties believe there could be a shortage of gas within a few years, unless new
sources of gas are discovered. Because of commitments made in this Agreement by
Buyer, Seller commits to a prudent and aggressive exploration program in the
Cook Inlet area as outlined in this Article II in order to increase gas reserves
available to ENSTAR and its customers.

            2.1.1 In anticipation of entering into this Agreement, Seller has
spent approximately $3 million in identifying, acquiring, and preparing a
comprehensive exploration program. Additionally, Seller has incurred over $1
million in overhead expenses associated with this program.

            2.1.2 Seller commits to spend in excess of $1 million in lease
rentals, seismic data and additional land acquisition costs within three years
of the Effective Date.

            2.1.3 Seller commits to spend in excess of $500,000 on technical
staff salaries allocated to gas exploration within two years of the Effective
Date.

            2.1.4 Seller commits to spend in excess of $10 million for costs
associated with drilling, completing and testing exploration wells that target
new Gas reserves between October 1, 2000 and October 31, 2002.

      2.2 EXPLORATION AREA: Seller agrees to make the additional expenditures
and pursue the exploration program committed to in Section 2.1 in new areas
outside of gas fields presently identified with a Field or Pool code by the
Alaska Oil and Gas Conservation Commission. It is the intent of Seller to
identify,

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develop, and produce new reserves from new fields, and to acquire and deliver
new gas into the Cook Inlet area, including Anchor Point, Ninilchik and Homer.

      2.3 MATERIAL CONSIDERATION: This exploration commitment is material
consideration for Buyer to make this Agreement. If Seller fails to meet its
exploration commitment, Buyer has all remedies available at law or in equity
except as limited by Section 13.10.

                                   ARTICLE III
                            SALE AND PURCHASE OF GAS

      3.1 QUANTITY: Buyer is not required to purchase in any Year more Gas than
the Annual Purchase Obligation. Subject to that limitation, Buyer will purchase
and Seller will sell Gas in the quantities determined by this Article.

      3.2 INITIAL COMMITMENT: The Initial Commitment is the quantity of Gas
necessary to make Buyer's Unmet Requirements equal zero in 2003, 2004, and 2005.
Forecasts indicate that purchases of the Initial Commitment will start on
January 1, 2004, but Buyer will actually begin taking the Initial Commitment
when it first has Unmet Requirements (but not before January 1, 2003).

      3.3 ADDITIONAL UNOCAL COMMITMENTS: Each Year beginning October 1, 2002,
Seller may commit additional Gas to Buyer as follows:

            3.3.1 Exhibit C is Buyer's Forecast for ten Years beginning January
1, 2001. Buyer's Forecast is an estimate of (1) Requirements and (2) Gas that
Buyer is obligated to purchase from: Buyer's Existing Commitments, the Initial
Commitment, Additional Third-Party Commitments, and Additional Unocal

                                       10
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Commitments. Buyer's Forecast also estimates Maximum Deliverability and the
portion of that Maximum Deliverability that Buyer has the right to purchase
from: Buyer's Existing Commitments, the Initial Commitment, Additional
Third-Party Commitments, and Additional Unocal Commitments.

            3.3.2 On or before October 1 of each Year beginning October 1, 2001,
Buyer will give Seller an updated Buyer's Forecast for the next ten Years. By
October 10 of each year, Seller must give Buyer a Seller's Commitment and may
elect to commit additional Gas to Buyer for any Year of Buyer's Forecast that
shows Unmet Requirements. Seller's Commitment will be in the form shown in
Exhibit D and will show the amount of Gas committed to Buyer for each Year of
Buyer's Forecast and the maximum amount of Gas Seller will have available for
Buyer each Day of each Year. The additional commitment is defined as an
"Additional Unocal Commitment" and becomes part of the Annual Purchase
Obligation.

            3.3.3 Buyer may make an Additional Third-Party Commitment at any
time but will not purchase Gas under an Additional Third-Party Commitment so
long as Unocal's Initial and Additional Commitments make Buyer's Unmet
Requirements equal zero for the following Commitment Periods:

     Commitment Date                            Commitment Period

     October 10, 2001                           2002, 2003, and 2004
     October 10, 2002                           2003, 2004, and 2005
     October 10, 2003                           2004, 2005, 2006, and 2007
     October 10, 2004 and October 10            the 5 Years following the
        of each following Year                      Commitment Date

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If Seller's Commitment is not given to Buyer by October 10 or if Seller's
Commitment does not commit to supply all of the Unmet Requirements for each year
of the Commitment Period, Buyer may purchase additional Gas to meet Unmet
Requirements during and after the Commitment Period. When determining Unmet
Requirements after the Commitment Period for purposes of this paragraph, Buyer
shall assume that Seller will supply the amount of Gas (and Deliverability) each
Year in the Years following the most recent Commitment Period that Seller has
committed to supply in the final Year of the most recent Commitment Period.

      Buyer may also contract to purchase Gas from third parties to supply
communities or areas not connected to the Pipeline System. For example, Buyer
could purchase Gas from a third party from a field near Homer to be delivered to
Homer through a pipeline not connected to the Pipeline System. If the community
or area is later connected to the Pipeline System, Gas may be purchased under
that contract in quantities which do not exceed the amount necessary to serve
that community or area and the contract may, at Buyer's option, be treated as if
it had been an Existing Commitment on the Effective Date of this Agreement.

            3.3.4 The making of Unocal's Initial and Additional Commitments and
the delivery of Gas under Unocal's Commitment are subject to the following
rules:

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            (i) Seller may not reduce its commitment to supply Unmet
Requirements in 2003, 2004, and 2005 unless it does not have adequate Gas to
meet that commitment after meeting Seller's Existing Commitments;

            (ii) a commitment for any Year cannot be more than 3 Bcf less than
the prior Year's commitment. For example, if the commitment in Bcf were 18, 16,
and 14 for the next three Years, commitments for Years 4 through 7 could not be
less than 11, 8, 5, and 2 Bcf respectively. In a Year in which the commitment is
Unmet Requirements, the Buyer's Forecast of Unmet Requirements for that Year
shall be used to calculate the limits imposed by this paragraph;

            (iii) Buyer's Requirements, including the Maximum Deliverability,
during an actual Year may be different from the Requirements estimated in
Buyer's Forecast. Seller's Deliverability and annual obligations shall be
determined by Buyer's actual Requirements, not the estimates in Buyer's
Forecast. If, for example, Buyer's Forecast showed Unmet Requirements of 10 Bcf
in Year X, Seller committed to satisfy Unmet Requirements in Year X, and actual
Unmet Requirements in Year X were 10.1 Bcf, Seller would be obligated to supply
10.1 Bcf.

      This provision is intended to accommodate expected growth, normal
fluctuations in Requirements, and to recognize that forecasting is imperfect. It
is possible that a new or former customer could increase Requirements
significantly and that Buyer would not be aware of the potential increase when
it prepared

                                       13
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Buyer's Forecast. If, after preparing a Buyer's Forecast, Buyer learns that its
Requirements may increase by ten percent (10%) or more in any Year of that
Buyer's Forecast (e.g., if a former large customer tells ENSTAR in February that
it wishes to be a customer again), Buyer will notify Seller and revise Buyer's
Forecast. Within thirty (30) Days, Seller will tell Buyer whether it can supply
the additional Gas and, if so, Seller's Commitment to Buyer will be increased
accordingly. If Seller is unable to supply the additional Gas, Buyer may
purchase the Gas from a third party.

            (iv) Deliverability:

            (a) If on a Commitment Date Seller commits Gas sufficient to make
Buyer's Unmet Requirements equal zero for any Years in the Commitment Period,
for those Years Seller must commit to supply that portion of Maximum
Deliverability not expected to be supplied from Buyer's Existing Commitments as
shown on the current Buyer's Forecast;

            (b) In any Year in which Seller does not commit Gas sufficient to
make Buyer's Unmet Requirements equal zero, Deliverability may not be less than
Seller's Pro Rata Share of the Maximum Deliverability;

            (c) Buyer may at any time request and Seller may, in its sole
discretion, supply Gas in excess of the Deliverability that Seller is required
to supply;

            (d) Buyer will request from Seller each Day approximately Seller's
Pro Rata Share of Total Daily Deliverability. Seller understands that changing
weather, fluctuations in Gas volumes from other suppliers, equipment

                                       14
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maintenance and failures, and other operating variables make it impossible for
Buyer to request every Day exactly Seller's Pro Rata Share of Total Daily
Deliverability.

            (v) By making the Initial Commitment and any Additional Unocal
Commitments, Seller dedicates to Buyer adequate Gas to satisfy those
commitments. Except for Seller's Existing Commitments, Buyer has first call on
Seller's Gas delivered into the Cook Inlet area necessary to meet Seller's
commitments to Buyer. Any agreement (including an amendment to Seller's Existing
Commitments or exercise of an option under Seller's Existing Commitments) made
on or after October 1, 2000 between Seller and a third party to dispose of
Seller's Gas must recognize this Agreement and Buyer's prior call on that Gas.

            (vi) Seller does not warrant that it has Gas adequate to
economically satisfy the Annual Purchase Obligations set under Article III.
Seller shall not be liable to Buyer, and Buyer shall not be entitled to the
remedy of cover, if Seller does not have Gas adequate to satisfy the Annual
Purchase Obligations. If Seller is unable, or has a reasonable basis for
believing that it will become unable, to satisfy the Annual Purchase Obligations
because its Gas supplies are not adequate to provide the Gas volume and
Deliverability necessary to meet the Annual Purchase Obligation, Seller shall
immediately notify Buyer and revise, as applicable, the Initial Commitment and
Additional Unocal Commitments to show the maximum portion of the Annual Purchase
Obligation Seller can supply. The

                                       15
<PAGE>

revised commitments will then be used in the Agreement as if they had been made
on the prior October 10th.

            (vii) No later than October 1st of each Year, and at anytime on
request with thirty (30) Days notice, Seller will give Buyer a forecast of the
maximum amount of Gas it can supply each Day ("Seller's Deliverability
Forecast") for the next ten (10) Years of the Agreement. At any time on request
and with thirty (30) Days notice, Buyer will update the Buyer's Forecast
prepared the prior October 1st.

            Seller shall, on request by Buyer, meet with Buyer to review data,
information, and well tests, sufficient to demonstrate Seller's ability to meet
its Commitments to Buyer. The information disclosed during any meeting is for
Buyer's internal use only and may not be disclosed to any third party without
Seller's prior written approval.

            (viii) There are various actions that Seller may take which will
determine or affect the amount of Gas that Buyer may purchase and when that Gas
may be purchased. These include making a Seller's Commitment, making a Seller's
Deliverability Forecast, and making a determination that Seller does not have
adequate Gas to meet its commitments. Each of the listed actions (except the
October 10, 2001 Seller's Commitment) must be supported by an opinion from the
Engineer: (1) that it is based on sound geologic, economic, and other data, (2)
that it is consistent with that data and this Agreement, and (3) that Seller
will be able to meet its Gas volume and Deliverability obligations under this
Agreement

                                       16
<PAGE>

consistent with sound engineering principles, and reasonable and prudent
operations. Buyer may also request that Seller supply an opinion from the
Engineer supporting any other action by Seller which materially affects the
amount of Gas Buyer may purchase and when the Gas may be purchased.

            3.3.5 All Additional Third-Party Commitments must recognize this
Agreement, and no Additional Third Party Commitment may reduce the Annual
Purchase Obligation in effect when the Additional Third-Party Commitment is
made.

            3.3.6 On March 1, 2001 Buyer will give Seller an updated Buyer's
Forecast. If in the March 1, 2001 Buyer's Forecast the difference between
Requirements and Existing Commitments for 2004, 2005, and 2006, collectively, is
less than 18 Bcf, Seller may delay the expenditure of funds committed to in
Article II by 12 months.

      3.4 GAS BALANCING: The quantity of Gas that Buyer actually purchases each
Year may not equal the quantity that Buyer is obligated to purchase ("Annual
Purchase Obligation") under Section 3.1 because of forecasting limitations,
changes in weather, and other operating factors. Buyer will not know the total
Gas purchased from other suppliers until shortly after year-end. Any difference
between the amount purchased from Seller and the Annual Purchase Obligation for
any Year ("Balancing Gas") shall be balanced in January and February of the next
Year using the following procedures:

                                       17
<PAGE>

            3.4.1 If in any Year Buyer purchases less than the Annual Purchase
Obligation for the reasons listed in Section 3.4 (deducting from actual
purchases any Balancing Gas taken during that Year to satisfy the Annual
Purchase Obligation of prior Years), in addition to the Annual Purchase
Obligation for the following Year the Balancing Gas shall be purchased in
January and February of the following Year. All Gas purchased in January and
February shall be deemed to be Balancing Gas until Buyer has purchased all the
Balancing Gas it is obligated to purchase.

            3.4.2 If all of the Balancing Gas is not taken during January and
February, Buyer shall pay in March (when the bill for February deliveries is
paid) for the Balancing Gas not taken. Buyer may take the Balancing Gas, paid
for but not taken at any time Seller has the Gas available during the three
Years following the Year in which payment was made, or before any earlier
termination of this Agreement, but the Balancing Gas shall not reduce the Annual
Purchase Obligation for each Year.

            3.4.3 If in any Year Buyer purchases more than the Annual Purchase
Obligation for the reasons listed in Section 3.4 (deducting from actual
purchases any Balancing Gas taken during that Year to satisfy prior Years), the
Balancing Gas shall be deducted from the Annual Purchase Obligation for the
following Year if, in Buyer's opinion, the deduction in the following Year is
necessary to comply with the terms of gas purchase agreements with third
parties.

                                       18
<PAGE>

            3.4.4 The price for Balancing Gas shall be the Price in effect for
the Year in which the Balancing Gas should have been purchased as part of the
Annual Purchase Obligation.

            3.4.5 Balancing Gas does not include Gas which Buyer is not.
obligated to purchase from Seller but which Buyer chooses to purchase from
Seller.

      3.5 UNANTICIPATED SHORTAGES: Buyer and ENSTAR are public utilities and
must attempt to meet the needs of customers. If Seller for any reason, including
a Force Majeure Event or a declaration under Section 3.6 that production is not
Economic, does not deliver all of the Gas it would otherwise be obligated to
deliver on any Day or if Buyer or ENSTAR for any reason, including a Force
Majeure Event, cannot take from Seller all of the Gas Buyer is obligated to take
on any Day, Buyer may acquire whatever Gas is necessary to cover the shortage.
In either event, Buyer will purchase or take only the amount of Gas necessary to
cover the shortage, but any purchases by Buyer to satisfy the shortage shall not
be deemed a waiver of any remedies or rights available to Buyer or Seller. If a
reduction of the purchases from Seller for any Year is attributable to actions
or inabilities of Seller, the Annual Purchase Obligation for that Year shall be
reduced by the amount of Gas purchased under this Section during that Year.

      3.6 GAS PRODUCTION NOT ECONOMIC: If the Seller forecasts and the Engineer
agrees that Gas production will not be Economic, Seller's obligation to produce,
deliver, and sell Gas will be suspended so long as production is expected

                                       19
<PAGE>

not to be Economic, but this Agreement will otherwise remain in effect until
terminated under Article V. "Economic" means that the proceeds (i.e., Price
times volume), net of all royalties, from the Gas exceed the cash out-of-pocket
costs (i.e., the costs which would not be incurred if the Gas were not produced)
of producing Gas with the required Deliverability. When determining whether
production is Economic, sunk costs will not be considered, and any potential
capital costs and other costs which would be incurred currently to benefit
production into the future will be amortized on a straight line over the
expected life of the remaining production including a rate of return on
investment equal to two percent over the interest rate set in Section 11.3 as of
the date of the Economic calculation. Seller cannot invoke this provision on
less than one hundred eighty (180) Days notice to Buyer. During any period that
Gas production is not Economic, Seller may make sales to third parties at a
Swing Rate of 1.2 or less. If Seller later forecasts and the Engineer agrees
that Gas production will become Economic, Gas production, sales and purchases
will resume except to the extent purchases are limited by Gas purchased under
Section 3.5 (Unanticipated Shortages).

      3.7 QUANTITY CALCULATION EXAMPLE: Exhibit B is a comprehensive example of
Article III.

      3.8 TITLE AND RISK OF LOSS: Title to, risk of loss, and liability for all
Gas sold and delivered by Seller and purchased and received by Buyer shall pass
to Buyer at the Receipt Point.

                                       20
<PAGE>

      3.9 OPERATIONAL COMMUNICATIONS: Buyer will notify Seller (or anyone
designated by Seller) by telephone periodically as to the volumes required by
Buyer. Seller recognizes that Buyer may change its volumes more than once each
Day and that a volume may not be changed for a number of Days. The purpose of
this Section is to provide communication between Buyer and Seller about field
operations and Buyer's needs. Communications under this Section do not change
the obligations of the Parties.

                                   ARTICLE IV
                          PRICE AND TRANSPORTATION FEE

      4.1 GAS PRICE: Buyer shall pay Seller a Gas price (the "Price") for each
Mcf of Gas purchased from Seller. The Price will be adjusted annually and the
adjusted Price will be in effect for the following Year.

            4.1.1 Price: The Price shall be the Daily Average Price of Henry Hub
Natural Gas Futures (HHNGF).

                  4.1.1.1 The Daily Average Price of HHNGF shall be determined
from the prices for "Henry Hub Natural Gas" futures contracts traded on the New
York Mercantile Exchange or its successor. The Daily Average Price of HHNGF
shall be the sum of the "Settle" prices reported for a contract traded during
the immediately previous thirty-six month period ended each September 30th of
the year prior to the year for which the Price is calculated for each day that
the contacts are reported as the contracts for the Current Trading Month divided
by the total number of days that such "Settle" prices are reported. "Current

                                       21
<PAGE>

Trading Month" means the final month in which a contact can be traded. The Daily
Average Price of HHNGF shall then be converted in to a price per Mcf using the
conversion factor of one (1) MMBTU equals one (1) Mcf.

      4.1.1.2 The Price shall not be less than the Floor Price. The Floor Price
shall be determined by the following formula:

                             FP = IP x [(1 + Adjuster) / 2]

             FP = Floor Price for any given Year (in $ per Mcf)

             IP = $2.75 per Mcf

             Adjuster = GDPIPD for the Quarter ended June 30 of the Year
                        before the Year for which the Price is calculated
                        -------------------------------------------------
                        GDPIPD for the Quarter ended June 30, 2001

      "GDPIPD" means the Gross Domestic Product Implicit Price Deflator prepared
by the Bureau of Economic Analysis, Economics and Statistics Administration,
United States Department of Commerce.

      4.2 REFERENCES: If the source of data or information used to calculate the
Price is not available or any Party, based on reasonable evidence, believes in
good faith that (i) the sources have been computed or published in error, or
(ii) the sources have so changed in the basis of calculation or reporting as to
materially alter the validity of the Price adjustments as originally
contemplated, then the Parties shall negotiate whether there is a reference
failure and an appropriate amendment to or replacement of the Price formula.

      4.3 CALCULATION: Buyer shall calculate the adjusted Price in October of
each Year and provide the calculation and supporting data to Seller by

                                       22
<PAGE>

November 1st of that Year. Within thirty (30) Days of receipt of the
calculation, Seller shall notify Buyer of the reasons for any objections to the
calculation.

      4.4 NO DETERMINATION: If an adjusted Price cannot be determined by January
1 of any Year, the current Price will be used until the adjusted Price is
determined. The current Price will then be changed retroactively to January 1st
and Buyer will promptly pay or receive a credit (with interest at the rate set
in Section 11.3) for the difference.

      4.5 TRANSPORTATION FEE: It is Seller's responsibility to build all
pipelines and other facilities necessary to deliver the Gas to the Receipt
Points. The Price includes all RCA-approved tariffs for pipelines operating on
the Effective Date of this Agreement. If pipelines are constructed after this
Agreement becomes effective, the Buyer shall reimburse Seller (in addition to
the Price) the RCA-approved tariff for the new pipelines used to deliver Gas to
Buyer, unless the RCA-approved tariff is more than $ 1.00 per Mcf. If the
RCA-approved tariff is more than $1.00 per Mcf, the Parties must agree to any
reimbursement in excess of $1.00 per Mcf. A pipeline is "used to deliver Gas to
Buyer" (i) if the pipeline transports Gas directly from the production field to
Buyer, (ii) if the pipeline is used to transport Gas to storage from which it is
later delivered to Buyer, or (iii) if the pipeline is used to deliver Gas to a
third party in exchange for Gas which will later be delivered to Buyer. The
tariff will be invoiced in the Month following the Month in which the Gas is
delivered to Buyer.

                                       23
<PAGE>

      4.6 PEAKING GAS FEE: Any Day that Seller supplies in excess of its Pro
Rata Share of Maximum Deliverability Seller will be paid a fee for the excess of
$ 1.00 per Mcf (in addition to the Price) increased or decreased each Year using
the Adjuster in paragraph 4.1.1.2.

      4.7 PRICE EXAMPLE: Exhibit F is a comprehensive example of the calculation
of Price.

                                   ARTICLE V
                                     TERM

      The Effective Date of this Agreement is the date on which it has been
executed by all Parties. Unless the Parties agree to extend this Agreement, this
Agreement shall terminate on the earlier of (a) delivery of all Gas committed to
be delivered, or (b) termination under another provision of this Agreement.

                                   ARTICLE VI
                                     TAXES

      6.1 GENERAL ALLOCATION: Seller shall pay all taxes, fees, penalties, and
assessments attributable to the Gas or any other activity or facility prior to
the Receipt Point. Buyer shall pay all taxes, fees, penalties, and assessments
attributable to the Gas or any other activity or facility at or after the
Receipt Point.

      6.2 SPECIFIC ALLOCATION: Buyer shall reimburse Seller for all Production
Taxes on Gas produced for sale to Buyer. Gas is "produced for sale to Buyer" (i)
if the Gas is delivered directly from the production field to Buyer, (ii) if the
Gas is produced and put into storage from which it is later delivered to Buyer,
or (iii) if

                                       24
<PAGE>

the Gas is produced and exchanged for Gas which will later be delivered to
Buyer. The Production Taxes shall be invoiced in the Month following the Month
in which the Gas is delivered to Buyer.

      6.3 NEW TAXES: The payment of any new taxes or increases in existing taxes
enacted or otherwise made effective after the date of this Agreement by any
governmental authority shall be allocated as provided in Sections 6.1 and 6.2.

      6.4 PRODUCTION TAX ADJUSTMENT: As provided in Section 11.1, Seller shall
bill Buyer each Month for Production Taxes due the State of Alaska on the Gas
purchased during the prior Month. The bill shall include the data and
calculations made to determine the Production Taxes. Any claim by Seller for
additional Production Taxes must be made within 180 Days of the initial billing.
Buyer shall not be responsible for interest on any additional Production Taxes.
If Seller determines at any time that it has overbilled Buyer for Production
Taxes, it shall credit Buyer with the overcharge, plus interest at the rate set
in Section 11.3, on the next Month's invoice.

                                   ARTICLE VII
                                   ROYALTIES

      Seller shall be responsible for the payment of all royalties, and any
fees, penalties and assessments attributable to the royalties, on Gas delivered
under this Agreement.

                                       25
<PAGE>

                                  ARTICLE VIII
                             RESERVED FOR FUTURE USE

                                   ARTICLE IX
                                    QUALITY

      9.1 HEATING VALUE OF GAS:

            9.1.1 Gas shall have a Gross Heating Value of not less than nine
hundred fifty (950) BTUs per Standard Cubic Foot nor more than one thousand
fifty (1,050) BTUs per Standard Cubic Foot.

            9.1.2 The Gross Heating Value of Gas shall be determined from a
representative composite Gas sample taken at the point of measurement by
periodic tests to be conducted monthly by Buyer or at such other intervals as
the Parties may mutually agree. The determination shall be made by means of a
calorimeter, or chromatograph, by calculation from the component analysis using
NGPA Publication 2145, as it may be revised, entitled "Physical Constants of
Paraffin Hydrocarbons or Other Compounds of Natural Gas."

      9.2 DELETERIOUS MATTER SPECIFICATION: Gas delivered to the Receipt Point,
or to a regulated pipeline operated by Buyer, shall be commercially free of
dust, gum, gum-forming constituents, or other liquid or solid matter that may
separate from the Gas in transportation, shall not exceed one hundred twenty
degrees Fahrenheit (120 degrees F.), and shall not contain:

                                       26
<PAGE>

            a. More than four (4) pounds of water per million Standard Cubic
Feet of Gas;

            b. More than one (1) grain of hydrogen sulfide per one hundred (100)
Standard Cubic Feet of Gas;

            c. More than twenty (20) grains of sulphur per one hundred (100)
Standard Cubic Feet of Gas;

            d. In excess of (i) three percent (3%) by volume of carbon dioxide;
or (ii) one percent (1 %) by volume of oxygen.

      9.3 FILTRATION OF GAS: Before commencing deliveries under this Agreement,
Seller shall install, operate and maintain a .3 micron screen coalescing filter
or other similar device to extract condensate from Gas prior to its delivery to
the Receipt Point.

      9.4 BUYER'S RIGHT TO REFUSE GAS: Buyer shall have the right to refuse to
accept delivery of any Gas failing to meet the quality requirements of this
Article IX. It is possible that Gas produced from some wells in Seller's oil and
gas fields will not meet the quality standards required by this Article because
of excess carbon dioxide or hydrogen sulfide. If Buyer refuses to accept that
Gas, and if Seller determines and the Engineer agrees that incurring the cost of
conditioning the Gas to meet the quality standards would not be Economic, Seller
may revise its Initial and Additional Commitments in accordance with Paragraph
3.3.4(vi).

                                       27
<PAGE>

                                    ARTICLE X
                    PRESSURE, MEASUREMENT, METERING, TESTING

      10.1 PRESSURE: Gas delivered under this Agreement shall be delivered at a
pressure sufficient to enter Buyer's Pipeline System at the Receipt Point, but
Seller shall not be required to deliver to the Receipt Point at a pressure
greater than 1050 PSIG.

      10.2 MEASUREMENT: Seller, at its expense, shall provide at the Receipt
Point continuous data showing Gas delivery rates. Buyer shall own, maintain and
operate, at Buyer's expense, measurement stations at or near the Receipt Point.
Unless agreed otherwise, the Receipt Point measurement station shall consist of
(a) standard measuring equipment conforming to the requirements of American Gas
Association Gas Measurement Committee Reports now in effect or as amended or
supplemented during the term of this Agreement, (b) appurtenant facilities, (c)
hydrometers, and (d) data telemetry equipment. Seller shall have access to the
Receipt Point measurement station(s) at which Seller tenders Gas at reasonable
hours, but Buyer will make all calibrations, measurements and adjustments. Buyer
will make available to Seller, and will not charge Seller for access to,
telemetry signals (pressure and flow rates) on Buyer's system that Seller
requires to manage its Gas supply and demand systems. Any new costs of acquiring
or using the telemetry signals shall be paid by Seller.

      10.3 INACCURATE METERS: If a meter is out of service or registering
inaccurately, the volumes of Gas delivered shall be estimated:

                                       28
<PAGE>

            a. by using the registration of the check meter or meters of Seller,
if installed, and accurately registering, or in the absence of (a),

            b. by correcting the error if the percentage of error is
ascertainable by calibration, test or mathematical calculations, or in the
absence of both (a) and (b), then,

            c. by estimating the quantity of deliveries based on deliveries
during comparable periods under similar conditions when the meter was
registering accurately.

      10.4 TESTING: Buyer will test the accuracy of the measuring equipment at
least once a Month. Buyer will give Seller reasonable advance notice so that
Seller may conveniently witness the tests. If Seller notifies Buyer that it
desires to test the accuracy of any measuring equipment, Buyer will test the
accuracy of the measuring equipment promptly after notification. Seller shall
have the right to witness the calibrating, adjusting and testing of the
measuring equipment. Buyer shall, on request, give its physical test and meter
proving reports to Seller. If there is a dispute about any measurement, the
Parties shall conduct a joint test that shall be dispositive. If the joint test
reveals there is an error, Buyer shall pay all costs associated with the joint
test. If the joint test reveals there was no error Seller shall pay all costs
associated with the joint test.

      10.5 CORRECTION: If any measuring equipment is found to be inaccurate by
one percent (1%) or less, previous records of the equipment shall be considered
accurate. If any measuring equipment is found to be inaccurate by more than one

                                       29
<PAGE>
percent (1%), any previous records of that equipment will be corrected to zero
error for any period known definitely or agreed upon. If a period of inaccuracy
is not definitely known or agreed upon, the correction shall be made for a
period of one-half (1/2) of the time elapsed since the date of the last test.
The correction shall fully settle all claims based on the inaccuracy. Any
measuring equipment found by test to be inaccurate, even if such error is less
than 1%, will immediately be adjusted or replaced, as appropriate, to measure
accurately.

      10.6 RECORDS: Each Party shall preserve for a period of at least six (6)
Years all test data, charts and other similar records for amounts of Gas
purchased under this Agreement.

      10.7 STANDARDS: Gas volumes shall be determined as follows:

            a. The unit of volume measurement shall be one Standard Cubic Foot
of Gas with correction for temperature and pressure deviation from the Ideal Gas
Laws according to ANSI/API 2530 or AGA Report No. 8, as applicable.

            b. The average absolute atmospheric pressure shall be assumed to be
fourteen and sixty-five hundredth (14.65) pounds per square inch, irrespective
of actual elevation or location of the Receipt Point above sea level or
variations in actual atmospheric pressure.

            c. The specific gravity of Gas shall be determined by the use of a
spot test method or, if the Parties later agree in writing, by the use of a
recording gravitometer generally accepted in the industry. If a recording
gravitometer is used, the arithmetic average of the specific gravity of Gas
flowing through the

                                       30
<PAGE>

meters shall be used in computing Gas volumes. If a spot test method is used,
the specific gravity of the Gas shall be determined at quarterly intervals, or
more often if changes in specific gravity indicate that it is necessary. Any
test shall determine the specific gravity to be used in computation of volumes
effective the first Day of the following Month and shall be used until changed
by subsequent test.

            d. The temperature of Gas shall be determined by a recording
thermometer so installed that it will record the temperature of the Gas flowing
through the meters. The average of the recorded temperatures to the nearest one
degree Fahrenheit (1 degree F.) obtained while Gas is being delivered shall be
used in computing measurements for that Day.

            e. Seller shall have the right to audit records of Buyer's volume
determinations for up to two years following delivery of Gas.

      10.8 CHECK METERS: Seller shall have the right to operate and maintain
check meters and other test equipment and devices at its expense.

                                   ARTICLE XI
                          BILLING, PAYMENT AND RECORDS

      11.1 BILLING: Seller shall provide Buyer on or before the second (2nd)
business day of each Month a statement showing its share of the total volume of
Gas delivered to each Receipt Point during the preceding Month. On or before the
tenth (10th) Day of each Month, Buyer shall furnish to Seller a statement
showing the total volume of Gas delivered during the preceding Month. By the
fifteenth (15th) Day of each Month, Seller shall give Buyer an invoice showing
the cost of

                                       31
<PAGE>

the Gas (i.e., the Price times the total volume), the transportation fee, if
any, any corrections for prior months, for the Gas, the Peaking Gas Fee, if any,
and Production Taxes due under Article VI. Buyer shall make payment to Seller by
check or wire transfer on or before the twenty-fifth (25th) Day of each Month.
Should Buyer's payment be different than the invoice amount, Buyer will provide
sufficient detail to support the adjustments made by Buyer to the invoice
amount. The Parties shall cooperate to resolve any disputed amount in a timely
manner. Buyer may, without prejudice to any claim or right, pay any disputed
amount and must pay any undisputed amount.

      11.2 RECORDS: Each Party shall have the right to inspect the files, books
and records of any other Party that pertain to this Agreement. Inspections shall
be conducted during regular business hours after reasonable notice. Adjustments
for any over or under payments shall be made promptly upon determination. All
billings shall be conclusively presumed final and accurate unless objected to in
writing within two (2) Years after the end of the Year in which the Gas was
delivered. The obligations to make payment for Gas received and to balance the
over and under deliveries, if any, to zero shall survive the termination or
cancellation of this Agreement.

      11.3 INTEREST: Any amount not paid when due (or any overpayment) shall
accrue interest daily at the prime rate charged by the First National Bank of
Anchorage or its successor (but not to exceed the maximum rate permitted by
law).

                                       32
<PAGE>

                                  ARTICLE XII
                    AGENCY PERMITS, APPROVALS AND AGREEMENTS

      12.1 RCA APPROVAL: This Agreement must be approved by the RCA before Buyer
purchases Gas. Buyer will submit this Agreement to the RCA within thirty (30)
Days of the Effective Date of the Agreement. Buyer will, at its expense, proceed
diligently, using its best efforts to obtain RCA approval. Buyer will give
Seller copies of all pleadings and will keep Seller informed about the status of
the RCA proceedings. Seller will cooperate with and assist Buyer in Buyer's
efforts to obtain RCA approval.

            12.1.1 APPROVAL DEFINED: This Agreement shall be deemed approved
when the RCA issues an order, not subject to further appeal, finding that all
costs of purchasing the Gas are fully recoverable in the rates of ENSTAR.

            12.1.2 TERMINATION: If the RCA does not approve all the terms of
this Agreement or if it imposes terms and conditions unacceptable to Buyer or
Seller, Buyer or Seller may terminate the Agreement by giving notice of
termination within thirty (30) Days of the date the RCA's order is served. If
the RCA has not approved this Agreement by December 31, 2001, any Party may
terminate the Agreement after thirty (30) Days notice.

      12.2 DNR AGREEMENT: Seller is not required to make investments, sell or
deliver Gas under this Agreement until Seller has negotiated and entered into an
agreement with the DNR containing terms and conditions acceptable to Seller (in
its sole discretion) clarifying Seller's obligations to the DNR under existing

                                       33
<PAGE>

royalty agreements and lease agreements as they relate to Gas sales to Buyer and
the Alaska Nitrogen Products fertilizer plant. Seller will, at its expense,
proceed diligently to obtain the DNR agreement required by this Section. Seller
will keep Buyer informed about the status of its negotiations with DNR. Buyer
will cooperate with and assist in Seller's efforts to obtain DNR agreement.

            12.2.1 AGREEMENT DEFINED: The DNR agreement shall be deemed obtained
when DNR and Seller have a written agreement that DNR will not, as a result of
Gas sales under this Agreement, cause royalty obligations to be due and payable
by Seller that Seller is unwilling to accept.

            12.2.2 If the DNR agreement has not been obtained by December 31,
2001, and Seller has not waived the approval required by paragraph 12.2 in
writing, either Party may terminate this Agreement after thirty (30) Days
notice.

                                  ARTICLE XIII
                                  BOILER PLATE

      13.1 FORCE MAJEURE:

            a. Non-Performance: No Party shall be responsible for any loss or
damage to another Party resulting from any delay in performing or failure to
perform any obligation under this Agreement (other than Buyer's obligation to
make payments due and owing under this Agreement) if the failure or delay is
caused by a Force Majeure Event.

            b. Force Majeure Event: "Force Majeure Event" means any event that
directly or indirectly renders a Party unable, wholly or in part, to

                                       34
<PAGE>

perform or comply with any obligation, covenant or condition in this Agreement
if the event, or the adverse effects of the event, is outside of the control of,
and could not have been prevented by, the affected Party with reasonable
foresight, at reasonable cost, and by the exercise of reasonable diligence in
good faith, and is not attributable to the negligence or willful misconduct of
the affected Party. Force Majeure Events include without limitation the
following events (to the extent they otherwise satisfy the definition):

               i. act of God, fire, lightning, landslide, earthquake, storm,
hurricane, hurricane warning, flood, high water, washout, explosion, or well
blowout;

               ii. strike, lockout, or other industrial disturbance, act of the
public enemy, war, military operation, blockade, insurrection, riot, epidemic,
arrest or restraint by government of people, terrorist act, civil disturbance,
or national emergency;

               iii. the inability of the affected Party to acquire, or the delay
on the part of the affected Party in acquiring materials, supplies, machinery,
equipment, servitudes, right-of-way grants, pipeline shipping capacity,
easements, permits or licenses, approvals, or authorizations by regulatory
bodies or oil and gas lessors needed to enable the Party to perform;

               iv. breakage of or accident to machinery, equipment, facilities,
or lines of pipe, and the repair, maintenance, improvement, replacement, test,
or alteration to the machinery, equipment, facilities, or lines of pipe, and the

                                       35
<PAGE>

freezing of a well or line of pipe, well blowout, or the partial or entire
failure of a Gas well; or

               v. act, order, or requisition of any governmental agency or
acting governmental authority, or any governmental law, proration, regulation,
or priority.

            c. Notice and Remedy: The Party claiming the excuse of Section 13.1
(a) shall:

               i. notify the other Party of the Force Majeure Event within a
reasonable time after its occurrence, giving reasonably full particulars and its
best estimate of the time required to remedy the Force Majeure Event;

               ii. keep the other Party informed of all significant
developments;

               iii. exercise diligence in good faith to remedy the Force Majeure
Event and resume full performance under this Agreement as soon as reasonably
practicable (except that the settlement of strikes, lockouts, or other labor
disputes or the restoration of a failed Gas well shall be entirely within the
discretion of the affected Party); and

               iv. if the Party claiming the Force Majeure Event estimates that
the Force Majeure Event will not be remedied for twelve (12) Months or more, the
other Party may terminate this Agreement on sixty (60) Days notice.

                                       36
<PAGE>

      13.2 BINDING ON SUCCESSORS: This Agreement shall be binding upon and inure
to the benefit of the legal representatives, successors and assigns of the
Parties.

      13.3 ASSIGNMENTS AND OTHER TRANSFERS. No Party may assign its obligations
under this Agreement without first obtaining the written consent of the other
Party, which consent shall not be unreasonably withheld or delayed. No consent
shall be required: (1) if all or substantially all of the assets of a Party are
acquired by another person; (2) if all or substantially all of the Alaska or
Cook Inlet area assets of a Party are transferred to a wholly owned subsidiary
of that Party; or (3) in the event of a merger, consolidation or reorganization
of a Party with another person. In the event of an acquisition, asset transfer,
merger, reorganization, stock transfer, corporate restructuring or
consolidation, the acquiring or surviving entity shall assume the obligations
and benefits of this Agreement. Nothing contained in this Section shall in any
way prevent any Party from pledging or mortgaging its rights under the Agreement
as security for its indebtedness.

      13.4 EASEMENTS AND RIGHTS-OF-WAY: Seller and Buyer, at no expense to the
other, grant and assign to each other all necessary easements and rights-of-way
for the construction of pipelines or other facilities necessary or convenient
for the delivery or receipt of Gas under this Agreement.

      13.5 GOVERNING LAW: This Agreement shall be governed by and construed in
accordance with the laws of the State of Alaska, excluding its rules of
conflicts

                                       37
<PAGE>

of laws that would refer it to the laws of another jurisdiction. The Parties
agree that any judicial proceeding shall be brought in the state courts for the
State of Alaska in Anchorage.

      13.6 AGREEMENT NOT TO BE CONSTRUED AGAINST EITHER PARTY AS DRAFTER: The
Parties recognize that this Agreement is the product of the joint efforts of the
Parties and agree that it shall not be construed against either Party as
drafter.

      13.7 NOTICES: All notices, consents, requests, demands, instructions,
approvals and other communications permitted or required shall be made in
writing by two of the following methods: (a) personally delivered, (b) delivered
and confirmed by facsimile transmission, (c) delivered by Federal Express, DHL
or other reputable overnight courier delivery service, (d) e-mail, or (e)
deposited in the United States mail, first class, postage prepaid, certified or
registered, return receipt requested, addressed as follows:

      If to Seller:

            For Gas Sales and Scheduling:

                       Attention:      Cook Inlet Gas Team Leader
                       Address:        Physical:    909 West Ninth Avenue
                                                    Anchorage, AK 99501
                                       Mailing:     P.O. Box 196247
                                                    Anchorage, AK 99519-6247
                       Telephone:      (907)276-7600
                       Facsimile:      (907)263-7874

                                       38
<PAGE>

            For Payments:

                       Attention:      Accounts Receivable
                       Address:        Physical:    909 West Ninth Avenue
                                                    Anchorage, AK 99501
                                       Mailing:     P.O. Box 196247
                                                    Anchorage, AK 99519-6247
                       Telephone:      (907) 276-7600
                       Facsimile:      (907) 263-7828

            For All Other Notices:

                       Attention:      Land and Governmental Affairs Manager
                       Address:        Physical:    909 West Ninth Avenue
                                                    Anchorage, AK 99501
                                       Mailing:     P.O. Box 196247
                                                    Anchorage, AK 99519-6247
                       Telephone:      (907) 263-7600
                       Facsimile:      (907) 263-7698

      If to Buyer:

            For Gas Sales and Scheduling:

                       Attention:      Vice President, Finance and Rates
                       Address:        Physical:    3000 Spenard Road
                                                    Anchorage, AK 99503
                                       Mailing:     P. O. Box 190288
                                                    Anchorage, AK 99519
                       Telephone:      (907) 264-3661
                       Facsimile:      (907) 264-3671

            For Payments:

                       Attention:      General Accounting Manager
                       Address:        Physical:    3000 Spenard Road
                                                    Anchorage, AK 99503
                                       Mailing:     P. O. Box 190288
                                                    Anchorage, AK 99519
                       Telephone:      (907) 264-3628
                       Facsimile:      (907) 272-3403

                                       39
<PAGE>

            Day-to-Day Operations and Scheduling:

                Attention:      Gas Control
                Address:        Physical:    401 E. International Airport Road
                                             Anchorage, AK 99518
                                Mailing:     P. O. Box 190288
                                             Anchorage, AK 99519
                Telephone:      (907) 264-3788
                Facsimile:      (907) 264-3779

            For All Other Notices:

                Attention:      Vice President, Finance and Rates
                Address:        Physical:    3000 Spenard Road
                                             Anchorage, AK 99503
                                Mailing:     P. O. Box 190288
                                             Anchorage, AK 99519
                Telephone:      (907) 264-3661
                Facsimile:      (907) 264-3671

or to any other place within the United States of America designated in writing.
All notices given by personal delivery, overnight courier, or mail shall be
effective on the date of actual receipt at the appropriate address. Notice
given by facsimile shall be effective upon actual receipt if received during
recipient's normal business hours or at the beginning of the next business Day
after receipt if received after the recipient's normal business hours.

      13.8 ENTIRE AGREEMENT: This Agreement constitutes the entire agreement and
understanding between the Parties about the subject matter of this transaction
and all prior agreements, understandings and representations, whether oral or
written, about this subject matter are merged into and superseded by this
written Agreement. No amendment to this Agreement shall be binding on either
Party until reduced to writing and signed by the Parties. This Agreement does
not

                                       40
<PAGE>

amend or otherwise affect the agreement effective May 1, 1988 between Seller and
Buyer.

      13.9 HEADINGS: The headings throughout this Agreement are for reference
purposes only and shall not be construed or considered in interpreting the terms
and provisions of this Agreement.

      13.10 NO INCIDENTAL OR CONSEQUENTIAL DAMAGES: Neither Party shall have any
liability to the other for incidental or consequential damages (including,
without limitation, lost profits) resulting from or arising out of this
Agreement.

      13.11 TERMINATION EVENTS:

            a. Termination Event Defined: Each of the following events is a
Termination Event: (i) any Party makes an assignment or general arrangement, for
the benefit of creditors; (ii) any Party defaults in its payment obligations
under this Agreement; (iii) any Party commences, authorizes, or acquiesces in
the commencement of a proceeding under any bankruptcy, insolvency, or similar
law, or has such a proceeding commenced against it; or (iv) any Party or any
Party's parent company becomes bankrupt or insolvent, or is unable to pay its
debts when due.

            b. Cure Period: If a Termination Event described in (ii) or (iv)
occurs, any non-defaulting Party may give notice to the defaulting Party
specifying the default. The defaulting Party shall have sixty (60) Days from the
notice to cure. If the default is not cured within sixty (60) Days, any
non-defaulting Party has the right to withhold or suspend deliveries or payment,
or

                                       41
<PAGE>

terminate this Agreement. If any other Termination Event occurs, any
non-defaulting Party has the right immediately to withhold or suspend deliveries
or payment, or terminate this Agreement. The right to terminate is limited by
Section 13.11

            c. Reservations: Each Party reserves all rights, set-offs,
counterclaims, and other defenses to which it is entitled under this Agreement.

      13.12 WAIVER: No failure or delay by any Party in exercising any right
under this Agreement shall operate as a waiver of that right, nor shall any
partial exercise of a right preclude any further exercise of that or any other
right. The rights shall be cumulative and not exclude any rights or remedies
provided by law.

      13.13 MULTIPLE ORIGINALS: Each copy of this Agreement that is properly
signed by all Parties shall be deemed an original.

      13.14 FEES AND COSTS: In the event of any action, or any judicial or
arbitration proceeding to resolve any dispute under this Agreement, or to
enforce any term of this Agreement, or to protect or preserve any rights under
this Agreement, the prevailing party shall be entitled to an award of costs and
actual reasonable attorney fees incurred. In the event of any bankruptcy
proceeding, including relief from stay, assumption or rejection of executory
contracts or transfer avoidance, the debtor in bankruptcy shall pay all costs
and actual reasonable attorney fees incurred by the non-debtor Parties, which
payment shall be necessary to the cure of all defaults under this Agreement.

                                       42
<PAGE>

      13.15 AUTHORITY TO SIGN: Each person signing this Agreement warrants that
he or she has authority to sign the Agreement.

      13.16 FURTHER ASSURANCES: The Parties agree to do such further acts or
execute such further documents as may reasonably be required to effectuate this
Agreement.

                                             ALASKA PIPELINE COMPANY

                                             By /s/ Daniel M. Dieckgraeff
                                                ------------------------------
                                             Its: VICE PRESIDENT
                                             Date:11-17-00

                                             UNION OIL COMPANY OF
                                                  CALIFORNIA

                                             By /s/ Charles A. Pierce, III
                                                ------------------------------
                                             Its: VICE PRESIDENT
                                             Date: 11-17-00

                                       43
<PAGE>

                                    EXHIBIT A

                       TO THE GAS SALES AGREEMENT BETWEEN
                         UNION OIL COMPANY OF CALIFORNIA
                           AND ALASKA PIPELINE COMPANY

                          BUYER'S EXISTING COMMITMENTS

1.    Agreement between Shell Oil Company and Alaska Pipeline Company dated
      December 20, 1982.

a.     Letter Agreement dated May 24, 1983 amending Agreement between Shell Oil
Company and Alaska Pipeline Company dated December 20, 1982.

b.     Agreement between Shell Western E & P, Inc. and Alaska Pipeline Company
dated January 26, 1988 amending Agreement between Shell Oil Company and Alaska
Pipeline Company dated December 20, 1982.

c.     Partial assignment of Agreement between Shell Oil Company and
Alaska Pipeline Company dated December 20, 1982, as amended, from Shell Western
E & P, Inc. to ARCO Alaska, Inc. effective October 1, 1989.

d.     Agreement between Alaska Pipeline Company and Shell Western E & P,
Inc. dated November 15, 1991, to amend a retained interest in the Agreement
between Shell Oil Company and Alaska Pipeline Company dated December 20, 1982,
as amended.

e.     Agreement between ARCO Alaska, Inc. and Alaska Pipeline Company dated
November 15, 1991, to amend an assigned interest in the Agreement between Shell
Oil Company and Alaska Pipeline Company, dated December 20, 1982, as amended.

f.     Partial assignment of Agreement between Shell Oil Company and
Alaska Pipeline Company dated December 20, 1982, as amended, from Shell Western
E & P, Inc. to Chevron U.S.A., Inc. effective January 1, 1993.

g.     Assignment of the retained interest in the Agreement between Shell Oil
Company and Alaska Pipeline Company dated December 20, 1982, as amended, from
Shell Western E & P, Inc. to the Municipality of Anchorage d/b/a Municipal Light
& Power effective September 1, 1996.

                                       44
<PAGE>

2.    Agreement between Phillips Petroleum Company and Alaska Pipeline Company
      dated November 26, 1984.

      a.    Amendment dated May 29, 1986 to Agreement between Phillips Petroleum
            Company and Alaska Pipeline Company dated November 26, 1984.

3.    Agreement between Marathon Oil Company and Alaska Pipeline Company dated
      May 1, 1988.

      a.    Amendment dated December 20, 1989 to the Agreement between Marathon
            Oil Company and Alaska Pipeline Company dated May 1, 1988.

      b.    Amendment dated November 19, 1991 to the Agreement between Marathon
            Oil Company and Alaska Pipeline Company dated May 1, 1988.

4.    Agreement between and among Anadarko Petroleum Corporation, Phillips
      Alaska, Inc. and Alaska Pipeline Company dated May 15, 2000.

                                       45
<PAGE>

                                    EXHIBIT B

                       TO THE GAS SALES AGREEMENT BETWEEN
               UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE
                                     COMPANY

                          QUANTITY CALCULATION EXAMPLES

This Exhibit contains examples of quantity calculations under Article III of the
Agreement. When computing the Annual Purchase Obligation (which will be stated
in Bcf), the calculations will be rounded to two decimal places. Intermediate
calculations will also be rounded to two decimal places and carried through the
calculation. Instructions for rounding are as follows:

    If the value of the digits      To round, drop all of the digits after
    following the second            the second decimal place and:
    decimal place is:

    Greater than .005               Add .01.

    Less than .005                  Do nothing.

    Equals .005                     Do nothing if the digit in the second
                                    decimal place is even. If the digit in the
                                    second  decimal place odd, add .01.
             Examples:

             19.16514    rounds to 19.17
             25.4721     rounds to 25.47
             19.145000   rounds to 19.14
             12.215000   rounds to 12.22

      1. Example 1 - Assume that on October 1, 2003, Buyer provides Seller with
a Buyer's Forecast (in accordance with Paragraph 3.3.2) that includes the
following information:

                                       46
<PAGE>

                HYPOTHETICAL BUYER'S FORECAST FOR OCTOBER 1, 2003

<TABLE>
<CAPTION>
                                       2004   2005   2006   2007    2008   2009   2010   2011   2012   2013
                                       -----  -----  -----  -----  ------  ----   ----   -----  -----  -----
<S>                                    <C>    <C>    <C>    <C>     <C>    <C>    <C>    <C>    <C>    <C>
      ANNUAL
 REQUIREMENTS (Bcf)
Requirements                           28.80  29.40  29.80  30.20   30.60  31.00  31.40  31.80  32.20  32.60
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
Existing Commitments:
  Beluga                                2.20   2.10   2.10   2.10    2.00   2.00   0.00   0.00   0.00   0.00
  Marathon APL-4                       17.00  15.00  13.00  11.00    9.00   7.00   5.00   5.00   5.00   5.00
  Moquawkie                             2.92   2.92   2.92   2.92    2.92   2.92   2.92   2.92   2.92   2.92
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
    Total Existing Commit.             22.12  20.02  18.02  16.02   13.92  11.92   7.92   7.92   7.92   7.92
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
Unocal Initial Commitment(1)            6.68   9.38   6.38   3.38    0.38   0.00   0.00   0.00   0.00   0.00
Additional Unocal Commit.               0.00   0.00   0.00   0.00    0.00   0.00   0.00   0.00   0.00   0.00
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
  Total Unocal Commitment               6.68   9.38   6.38   3.38    0.38   0.00   0.00   0.00   0.00   0.00
Additional Third-Party
   Commitments                          0.00   0.00   0.00   0.00    0.00   0.00   0.00   0.00   0.00   0.00
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
Unmet Requirements                      0.00   0.00   5.40  10.80   16.30  19.08  23.48  23.88  24.28  24.68
                                       =====  =====  =====  =====   =====  =====  =====  =====  =====  =====

      DAILY
 REQUIREMENTS (MMcf/d)
Maximum Deliverability                 207.1  212.2  215.1  218.0   220.3  223.9  226.9  229.8  232.1  235.7
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
Existing Commitments:

  Beluga                                15.8   15.2   15.2   15.2    14.4   14.5    0.0    0.0    0.0    0.0
  Marathon APL-4                       122.5  108.3   93.9   79.4    64.9   50.6   36.2   36.2   36.2   36.2
  Moquawkie                             20.0   20.0   20.0   20.0    20.0   20.0   20.0   20.0   20.0   20.0
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
    Total Existing Commit.             158.3  143.5  129.1  114.6    99.3   85.1   56.2   56.2   56.2   56.2
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
Unocal Initial Commitment               48.8   68.6   46.1   24.4     2.7    0.0    0.0    0.0    0.0    0.0
Additional Unocal Commit.                0.0    0.0    0.0    0.0     0.0    0.0    0.0    0.0    0.0    0.0
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
  Total Unocal Commitment               48.8   68.6   46.1   24.4     2.7    0.0    0.0    0.0    0.0    0.0
Additional Third-Party
   Commitments                           0.0    0.0    0.0    0.0     0.0    0.0    0.0    0.0    0.0    0.0
                                       -----  -----  -----  -----   -----  -----  -----  -----  -----  -----
 Unmet Requirements                      0.0    0.0   39.9   79.0   118.3  138.8  170.7  173.6  175.9  179.5
                                       =====  =====  =====  =====   =====  =====  =====  =====  =====  =====
</TABLE>

      Paragraph 3.3.2 requires Seller to make an election on or before October
10, 2003, whether to make an Additional Unocal Commitment. Assuming Seller makes
an Additional Unocal Commitment that meets the Unmet Requirements through 2007,
Seller's Commitment (Exhibit D) would be:

---------
(1)   The 3 Bcf/Year reduction beginning in 2006 illustrates the operation of
      paragraph 3.3.4(ii).

                                       47
<PAGE>
            FIRST HYPOTHETICAL SELLER'S FORECAST FOR OCTOBER 10, 2003

<TABLE>
<CAPTION>
                                         2004     2005     2006     2007     2008     2009     2010     2011     2012     2013
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
<S>                                      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
       ANNUAL
  REQUIREMENTS (BCF)
Requirements                             28.80    29.40    29.80    30.20    30.60    31.00    31.40    31.80    32.20    32.60
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Existing Commitments:
  Beluga                                  2.20     2.10     2.10     2.10     2.00     2.00     0.00     0.00     0.00     0.00
  Marathon APL-4                         17.00    15.00    13.00    11.00     9.00     7.00     5.00     5.00     5.00     5.00
  Moquawkie                               2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.               22.12    20.02    18.02    16.02    13.92    11.92     7.92     7.92     7.92     7.92
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment                 6.68     9.38     6.38     3.38     0.38     0.00     0.00     0.00     0.00     0.00
Additional Unocal Commit.                 0.00     0.00     5.40    10.80    10.80     8.18     5.18     2.18     0.00     0.00
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment                 6.68     9.38    11.78    14.18    11.18     8.18     5.18     2.18     0.00     0.00
Additional Third-Party
   Commitments                            0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00
                                         -----    -----    -----    -----    -----    -----    -----    -----   ------    -----
Unmet Requirements                        0.00     0.00     0.00     0.00     5.50    10.90    18.30    21.70    24.28    24.68
                                         =====    =====    =====    =====    =====    =====    =====    =====    =====    =====

        DAILY
 REQUIREMENTS (MMcf/d)
Maximum Deliverability                   207.1    212.2    215.1    218.0    220.3    223.9    226.9    229.8    232.1    235.7
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Existing Commitments:
  Beluga                                  15.8     15.2     15.2     15.2     14.4     14.5      0.0      0.0      0.0      0.0
  Marathon APL-4                         122.5    108.3     93.9     79.4     64.9     50.6     36.2     36.2     36.2     36.2
  Moquawkie                               20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.               158.3    143.5    129.1    114.6     99.3     85.1     56.2     56.2     56.2     56.2
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment                 48.8     68.6     46.1     24.4      2.7      0.0      0.0      0.0      0.0      0.0
Additional Unocal Commit.                  0.0      0.0     39.9     79.0     77.8     59.1     37.4     15.8      0.0      0.0
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment                 48.8     68.6     86.0    103.4    80.50     59.1     37.4     15.8      0.0      0.0
Additional Third-Party
   Commitments                             0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0
                                         -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
 Unmet Requirements                        0.0      0.0      0.0      0.0     40.5     79.7    133.3    157.8    175.9    179.5
                                         =====    =====    =====    =====    =====    =====    =====    =====    =====    =====
</TABLE>

      Because Seller is committed to supply Unmet Requirements through 2007,
Buyer will not purchase Gas in the Years 2004, 2005, 2006 and 2007 under an
Additional Third-Party Commitment (see Paragraph 3.3.3). For planning purposes
for the Years beyond the Commitment Period covered in the October 10, 2003
Seller's Commitment (i.e., for Years after 2007), Buyer must assume that Seller
could provide as much as

                                       48
<PAGE>

Unmet Requirements (including the related Deliverability). In accordance with
Paragraph 3.3.4(ii), Seller's Commitment for 2008 (when given on October 10,
2004) cannot be more than 3 Bcf less than that of a prior year (in this example,
11.18 Bcf and the related Deliverability).

      Assume further that the year is 2004 and Buyer's actual Requirements(2)
are 29,282,529 Mcf (29.282529 Bcf) and Existing Commitments are 22.2 Bcf for
2004. Buyer's actual Unmet Requirements for 2004 would be calculated as follows:

      Unmet Requirements  =  Requirements - Existing Commitments

      Unmet Requirements  =   29,282,529 Mcf - 22,200,000 Mcf

      Unmet Requirements  =   7,082,529 Mcf  =  2004 Unmet Requirements

The Annual Purchase Obligation for 2004, in accordance with Paragraph
3.3.4(iii), would be Buyer's actual Unmet Requirements, 7,082,529 Mcf.

            To illustrate the balancing provision, assume that for the Year
ended December 31, 2004, Buyer had actually taken 7,202,554 Mcf from Seller and
22,079,975 Mcf from Existing Commitments. Buyer would have overtaken from Seller
(and undertaken from Existing Commitments) by 120,025 Mcf (Balancing Gas). Under
Paragraph 3.4.3 (and to comply with the terms of the Existing Commitments
contracts), 120,025 Mcf would be deducted from the Annual Purchase Obligation
for the following year, 2005. The 120,025 Mcf would also be priced at the 2005
Price.

      3. Example 2 - Assume the same facts in Example 1, except that Seller
elects to commit only to a portion, 4.6 Bcf, of the 2006 Unmet Requirements and
to

                                       49
<PAGE>

provide the same total amount of Gas in 2007 as in 2006. Seller's Commitment for
October 10, 2003 would be as follows:

           SECOND HYPOTHETICAL SELLER'S FORECAST FOR OCTOBER 10, 2003

<TABLE>
<CAPTION>
                                 2004      2005     2006     2007     2008     2009     2010     2011     2012     2013
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
<S>                              <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
        ANNUAL
  REQUIREMENTS (BCF)
Requirements                     28.80    29.40    29.80    30.20    30.60    31.00    31.40    31.80    32.20    32.60
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Existing Commitments:
  Beluga                          2.20     2.10     2.10     2.10     2.00     2.00     0.00     0.00     0.00     0.00
  Marathon APL-4                 17.00    15.00    13.00    11.00     9.00     7.00     5.00     5.00     5.00     5.00
  Moquawkie                       2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92     2.92
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.       22.12    20.02    18.02    16.02    13.92    11.92     7.92     7.92     7.92     7.92
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment         6.68     9.38     6.38     3.38     0.38     0.00     0.00     0.00     0.00     0.00
Additional Unocal Commit.         0.00     0.00     4.60     7.60     7.60     4.98     1.98     0.00     0.00     0.00
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment         6.68     9.38    10.98    10.98     7.98     4.98     1.98     0.00     0.00     0.00
Additional Third-Party
   Commitments                    0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unmet Requirements                0.00     0.00     0.80     3.20     8.70    14.10    21.50    23.88    24.28    24.68
                                 =====    =====    =====    =====    =====    =====    =====    =====    =====    =====

        DAILY
 REQUIREMENTS (MMcf/d)
Maximum Deliverability           207.1    212.2    215.1    218.0    220.3    223.9    226.9    229.8    232.1    235.7
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Existing Commitments:

  Beluga                          15.8     15.2     15.2     15.2     14.4     14.5      0.0      0.0      0.0      0.0
  Marathon APL-4                 122.5    108.3     93.9     79.4     64.9     50.6     36.2     36.2     36.2     36.2
  Moquawkie                       20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0     20.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.       158.3    143.5    129.1    114.6     99.3     85.1     56.2     56.2     56.2     56.2
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment         48.8     68.6     46.1     24.4      2.7      0.0      0.0      0.0      0.0      0.0
Additional Unocal Commit.          0.0      0.0     33.2     54.9     54.7     36.0     14.3      0.0      0.0      0.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment         48.8     68.6     79.3     79.3     57.4     36.0     14.3      0.0      0.0      0.0
Additional Third-Party
   Commitments                     0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
 Unmet Requirements                0.0      0.0      6.7     24.1     63.6    102.8    156.4    173.6    175.9    179.5
                                 =====    =====    =====    =====    =====    =====    =====    =====    =====    =====
</TABLE>

      Because Seller did not commit to 100% of the Unmet Requirements in 2006
and 2007, the "unfilled" Unmet Requirements for those years can be purchased
from to a third party (see Paragraph 3.3.3). For planning purposes for the Years
beyond the

--------
(2)   As distinct from Requirements shown in Buyer's Forecast.

                                       50
<PAGE>

Commitment Period covered in the October 10, 2003 Seller's Commitment (i.e., the
Years after 2007), Buyer must assume that Seller could provide as much Gas as
Seller's Commitment in 2007 (10.08 Bcf and the related Deliverability in this
example). In accordance with Paragraph 3.3.4(ii), Seller's Commitment, including
related Deliverability, for 2008 (when given on October 10, 2004) cannot be more
than 3 Bcf less than that of a prior year (in this example, 7.98 Bcf).

                                       51
<PAGE>

                                    EXHIBIT C

                       TO THE GAS SALES AGREEMENT BETWEEN
           UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY

                            BUYER'S TEN YEAR FORECAST

<TABLE>
<CAPTION>
                                 2001      2002     2003     2004     2005     2006     2007     2008     2009     2010
                                 -----    -----    -----    -----    -----     ----    -----    -----    -----    -----
<S>                              <C>       <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
        ANNUAL
    REQUIREMENTS (BCF)
Requirements                     24.90    25.70    26.50    27.30    27.90    28.30    28.70    29.10    29.50    29.90
                                 -----    -----    -----    -----    -----     ----    -----    -----    -----    -----
Existing Commitments:
  Beluga                          3.90     2.80     2.70     1.70     1.60     1.60     1.60     1.50     1.50     0.00
  Marathon APL-4                 21.00    21.00    19.00    17.00    15.00    13.00    11.00     9.00     7.00     5.00
  Moquawkie                       0.00     1.90     4.80     2.92     2.92     2.92     2.92     2.92     2.92     2.92
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.       24.90    25.70    26.50    21.62    19.52    17.52    15.52    13.42    11.42     7.92
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment         0.00     0.00     0.00     5.68     8.38     5.38     2.38     0.00     0.00     0.00
Additional Unocal Commit.         0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment         0.00     0.00     0.00     5.68     8.38     5.38     2.38     0.00     0.00     0.00
Additional Third-Party
   Commitments                    0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00     0.00
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unmet Requirements                0.00     0.00     0.00     0.00     0.00     5.40    10.80    15.68    18.08    21.98
                                 =====    =====    =====    =====    =====    =====    =====    =====    =====    =====
        DAILY
  REQUIREMENTS (MMcf/d)
Maximum Deliverability           180.8    186.7    192.5    197.7    202.2    205.5    208.4    210.7    214.1    217.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Existing Commitments:
  Beluga                          28.3     20.3     19.6     12.3     11.6     11.6     11.6     10.9     10.9      0.0
  Marathon APL-4                 152.5    152.4    137.8    122.9    108.7     94.3     79.8     65.1     50.8     36.3
  Moquawkie                        0.0     14.0     33.1     20.0     20.0     20.0     20.0     20.0     20.0     20.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
    Total Existing Commit.       180.8    186.7    190.5    155.2    140.3    125.9    111.4     96.0     81.7     56.3
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
Unocal Initial Commitment          0.0      0.0      2.0     42.5     61.9     39.1     17.3      0.0      0.0      0.0
Additional Unocal Commit.          0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
  Total Unocal Commitment          0.0      0.0      0.0     42.5     61.9     39.1     17.3      0.0      0.0      0.0
Additional Third-Party
   Commitments                     0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0      0.0
                                 -----    -----    -----    -----    -----    -----    -----    -----    -----    -----
 Unmet Requirements                0.0      0.0      0.0      0.0      0.0     40.5     79.7    114.7    132.4    160.7
                                 =====    =====    =====    =====    =====    =====    =====    =====    =====    =====
</TABLE>

The Beluga contract is the agreement between Shell Oil Company and Alaska
Pipeline Company dated December 20, 1982, as amended, in Exhibit A.

The Marathon APL-4 contract is the agreement between Marathon Oil Company and
Alaska Pipeline Company dated May 1, 1988, as amended, in Exhibit A.

                                       52
<PAGE>

The Moquawkie contract is the agreement between and among Anadarko Petroleum
Corporation, Phillips Alaska, Inc. and Alaska Pipeline Company dated May 15,
2000 in Exhibit A.

                                       53
<PAGE>

                                    EXHIBIT D

                       TO THE GAS SALES AGREEMENT BETWEEN
           UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY

                 SAMPLE SELLER'S COMMITMENT FOR OCTOBER 10, 2003

This Sample Seller's Commitment shows the form Seller will use each Year to make
Seller's Commitment as required by paragraph 3.3.3. Because the passage of time
will require the substitution of numbers and the addition of Years, this form is
a sample.

<TABLE>
<CAPTION>
                                         2004     2005     2006     2007     2008     2009     2010    2011    2012    2013
                                         -----    -----    -----    -----    -----    -----   -----    -----   -----   -----
<S>                                      <C>      <C>      <C>      <C>      <C>      <C>     <C>      <C>     <C>     <C>
       ANNUAL
 REQUIREMENTS (BcF)
Requirements                             27.30    27.90    28.30    28.70    29.10    29.50    29.90   xx.xx   xx.xx   xx.xx
                                         -----    -----    -----    -----    -----    -----    -----   -----   -----   -----
Existing Commitments                     21.62    19.52    17.52    15.52    13.42    11.42     7.92   xx.xx   xx.xx   xx.xx
                                         -----    -----    -----    -----    -----    -----    -----   -----   -----   -----
Prior Unocal Commitments(3)               5.68     8.38     5.38     2.38     0.00     0.00     0.00    0.00    0.00    0.00
Additional Third Party Commitments
Unmet Requirements                        0.00     0.00     5.40    10.80    15.68    18.08    21.98    0.00    0.00    0.00
                                         =====    =====    =====    =====    =====    =====    =====   =====   =====   =====
                                                             __       __
Additional Unocal Commit.                 0.00     0.00     /__/     /__/
                                         -----    -----      __       __
  Total Unocal Commitment                                   /__/     /__/                                               0.00

        DAILY
 REQUIREMENTS (MMcf/d)
Maximum Deliverability                   197.7    202.2    205.5    208.4    210.7    214.1    217.0   xxx.x   xxx.x   xxx.x
                                         -----    -----    -----    -----    -----    -----    -----   -----   -----   -----
Prior Unocal Commitments                  42.5     61.9     39.1     17.3      0.0      0.0      0.0     0.0     0.0     x.0
Existing Commitments                     155.2    140.3    125.9    111.4     96.0     81.7     56.3   xxx.x   xxx.x   xxx.x
                                         -----    -----    -----    -----    -----    -----    -----   -----   -----   -----
Additional Third Party Commitments
Unmet Requirements                         0.0      0.0     40.5     79.7    114.7    132.4    160.7     0.0     0.0     0.0
                                         =====    =====    =====    =====    =====    =====    =====   =====   =====   =====
                                                             __       __
Additional Unocal Commit.                                   /__/     /__/
                                                             __       __
  Total Unocal Commitment                                   /__/     /__/                                                0.0
</TABLE>

 Unocal commits to supply that amount of Gas (and Deliverability) for each Year
indicated in the box corresponding to the Additional Unocal Commitments for the
years 2006 and 2007, the years within the Commitment Period ending December 31,
2007 showing an Unmet Requirement. Seller's Commitment of an amount of Gas which
 makes Buyer's forecast Unmet Requirements equal zero is a commitment to supply
                   Buyer's Unmet Requirements for that Year.

----------
(3)   Prior Unocal Commitments is the sum of Unocal's Initial Commitment and any
      Additional Commitments

                                       54
<PAGE>

This commitment is subject to the terms and conditions of the Gas Sales
Agreement Between Union Oil Company of California and Alaska Pipeline Company
effective November ____, 2000.

UNION OIL COMPANY OF CALIFORNIA

By ______________________________
Its: ______________________________
Date: ____________________________

Agreed to and Accepted
ALASKA PIPELINE COMPANY

By ______________________________
Its: ______________________________
Date: ____________________________

                                       55
<PAGE>

                                    EXHIBIT E

                       TO THE GAS SALES AGREEMENT BETWEEN
           UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY

                          SELLER'S EXISTING COMMITMENTS

A.    Gas produced and delivered from Seller's Properties, which is utilized to
      fulfill the obligations of Union Oil Company of California, its parent,
      affiliates, subsidiaries, legal representatives, successors in interest
      and assigns under that certain Gas Purchase and Sale Agreement of
      September 1, 1998, as amended effective January 1, 2000, between Union Oil
      Company of California and Kenai Fertilizer Company LLC, subsequently known
      as Alaska Nitrogen Products LLC. (NOTE: Alaska Nitrogen Products LLC was
      purchased by Agrium U.S. Inc. effective September 30, 2000. Agrium
      currently operates the assets of Alaska Nitrogen Products in the name of
      Agrium U.S. Inc., Kenai Nitrogen Operations.)

B.    Gas produced and delivered from Seller's Properties pursuant to the
      December 1, 1994, Swanson River Field Natural Gas Redelivery and Exchange
      Agreement, as heretofore amended.

C.    Gas produced and delivered for field uses, including without limitation
      for use as fuel and use for artificial lift operations.

D.    Gas produced and delivered to Forcenergy pursuant to the November 1, 1999,
      Amended and Restated Exploration Agreement, for emergency fuel gas for oil
      producing properties in Cook Inlet.

E.    Gas which is (1) produced from any Seller's Property acquired by Seller
      after the Effective Date, and which is (2) sold pursuant to a contract
      entered into by a predecessor in interest of Seller with respect to such
      property.

F.    1988 APL-Unocal Exchange Agreement, effective May 1, 1988.

G.    If final approval is received, the 1988 Marathon-Unocal Exchange
      Agreement, effective May 1, 1988, as amended and restated effective May 1,
      1998. The 1998 amendment to the 1988 Marathon Unocal Exchange Agreement
      has not received final approval. If final approval is not received, then
      the 1988 Marathon Unocal Exchange Agreement, effective May 1, 1988 will be
      a Seller's Existing Commitment.

                                       56
<PAGE>

                                    EXHIBIT F

                       TO THE GAS SALES AGREEMENT BETWEEN
           UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY

                            PRICE CALCULATION EXAMPLE

      This Exhibit is an example of the basic Price calculation under Article IV
of the Agreement.

      1.    Rounding - Price calculations will be rounded to four decimal
            places. Intermediate calculations (e.g., calculation of an average
            price) will also be rounded to four decimal places and carried
            through the calculation. Instructions for rounding are as follows:

            If the value of the digits      To round, drop all of the digits
            following the fourth decimal    after the fourth decimal place and:
            place is:

            Greater than .00005    Add .0001.

            Less than .00005       Do nothing.

            Equals .00005          Do nothing if the digit in the fourth decimal
                                   place is even. If the digit in the fourth
                                   decimal place odd, add .0001.

                   Examples:

                   19.1916514  rounds to 19.1917
                   25.624721   rounds to 25.6247
                   19.12145000 rounds to 19.1214
                   12.76215000 rounds to 12.7622

                                       57
<PAGE>

      2.    Price Calculation Example 1 - This example assumes that the Price is
            being calculated for 2005. Paragraph 4.1.1 provides that the Price
            shall be the Daily Average Price of Henry Hub Natural Gas Futures.

            a. Calculation of Daily Average Price of Henry Hub Natural Gas
Futures - Paragraph 4.1.1.1 provides that the Daily Average Price of Henry Hub
Natural Gas Futures (HHNGF) shall be determined from the sum of the "Settle"
prices reported for a contract traded during the immediately previous thirty-six
month period ended each September 30th of the year prior to the year for which
the Price is calculated for each day that the contacts are reported as the
contracts for the Current Trading Month divided by the total number of days that
such "Settle" prices are reported. "Current Trading Month" means the final month
in which a contact can be traded.

            In this example, the thirty-six month period for the calculation
would begin October 1, 2001 and end September 30, 2004 and the Current Trading
Month contract would be the November 2001 futures contract. Assume that the sum
of the Current Trading Month Settle prices for HHNGF each day in the thirty-six
month period ended September 30, 2004 is $2,229.453 per MMBTU and that the
values were reported for 729 days. The Daily Average Price of HHNGF for use in
2005 is:

      $2229.453   = 3.058234 . . .
      ----------
         729

      Rounded to four decimal places = $3.0582 per MMBTU

      Converted to price per Mcf using the conversion factor of one (1)
MMBTU equals one (1) Mcf = $3.0582 per Mcf = 2005 Daily Average Price of HHNGF

                                       58
<PAGE>

      b.    Calculation of Floor Price - Paragraph 4.1.1.2 provides that the
            Price shall not be less than the Floor Price. The Floor Price (FP)
            for any given year shall be:

            -     The Initial Price (IP) which equals $2.75 per Mcf

            -     Multiplied by [(1 plus the change in the Gross Domestic
                  Product Implicit Price Deflator (GDPIPD) from the quarter
                  ended in June of 2001 to the quarter ended in June of the Year
                  prior to the sale) divided by 2].

      In this example, the quarter ended in June of the Year prior to the sale
would be the quarter ended June of 2004. To illustrate the calculation, assume
the GDPIPD for the third quarter of 2004 is 127.69. The GDPIPD for the third
quarter of 2001 was 112.62. The change is:

                  127.69  = 1.1338128 . . .
                 --------
                  112.62

                  Rounded to four decimal places = 1.1338

      2005 Floor Price is:

                   $2.75 x [(1+1.1338) / 2] = Price

                   $2.75 x [2.1338 / 2] = Price

                   $2.75 x 1.0669 = $2.933975

      Rounded to four decimal places  =  $2.9340 = 2005 Floor Price

      "GDPIPD" (the Gross Domestic Product Implicit Price Deflator) used in the
calculation of "FP" in Article 4.1.1.2 shall be that which is calculated and
reported by the U.S. Department of Commerce, Economics and Statistics
Administration, Bureau of

                                       59
<PAGE>

Economic Analysis or its successor. The GDPIPD's employed shall be the "Final
Revision" for the second quarter of each year.

            c. Comparison of Daily Average Price of HHNGF to Floor Price - The
Average Daily Price of HHNGF for 2005 calculated in 2a. above was $3.0582 per
Mcf. It is higher than Floor Price for 2005 of $2.9304 per Mcf that was
calculated in 2b. above and shall be the Price for 2005.

            3. Price Calculation Example 2 - Assume everything in Price
Calculation Example 1 except that the sum of the Current Trading Month Settle
prices for HHNGF each day in the thirty-six month period ended September 30,
2004 is $2,029.453 per MMBTU and that the values were reported for 729 days. The
Daily Average Price of HHNGF is:

               $2029.453  = 2.783886 . . .
               ---------
                 729

               Rounded to four decimal places = $2.7839 per MMBTU

               Converted to price per Mcf using the conversion factor of one (1)
 MMBTU equals one (1) Mcf = $2.7839 per Mcf.

            In this example, the 2005 Daily Average Price of HHNGF would be less
than the 2005 Floor Price of $2.9304 per Mcf, therefore the 2005 Price would be
$2.9304.

                                       60
<PAGE>

                                    EXHIBIT G

                       TO THE GAS SALES AGREEMENT BETWEEN
                         UNION OIL COMPANY OF CALIFORNIA
                           AND ALASKA PIPELINE COMPANY

                                RECEIPT POINT(S)

1.    Beluga-Anchorage Pipeline

      a.    Beluga Pipeline Company Connection (ENSTAR/APC Metering Stations 700
            & 701)

            At the upstream flange of the Buyer's meter at or near the
            connection of the Buyer's Beluga-Anchorage pipeline and Beluga
            Pipeline Company's Granite Point-Beluga pipeline located within the
            West 1/2 of the Southwest 1/4 of Section 26, Township 13 North,
            Range 10 West, Kenai Peninsula Borough, Seward Meridian, State of
            Alaska.

      b.    Pretty Creek Unit Connection (ENSTAR/APC Metering Stations 189 A &
            B)

            At the upstream flange of the Buyer's meter at or near the
            connection of the Buyer's Beluga-Anchorage pipeline located in the
            South 1/2 of Section 28 Township 14 North, Range 9 West,
            Matanuska-Susitna Borough, Seward Meridian, State of Alaska.

      c.    Lewis River Unit Connection (ENSTAR/APC Metering Stations 168 A &B)

            At the upstream flange of the Buyer's meter at or near the
            connection of the Buyer's Beluga-Anchorage pipeline located in the
            Northwest 1/4 of Section 2, Township 14 North, Range 9 West,
            Matanuska-Susitna Borough, Seward Meridian, State of Alaska.

      d.    Stump Lake/Ivan River Connection (ENSTAR/APC Metering Stations 600 &
            601)

            At the upstream flange of the Buyer's meter located at or near the
            connection of the Buyer's Beluga-Anchorage pipeline the Southeast
            1/4 of the Northwest 1/4 of the Northeast 1/4 of the Southwest 1/4
            of Section 22, Township 14 North, Range 9 West, Seward Meridian,
            State of Alaska.

2.    Kenai-Anchorage Pipeline

      a.    Kenai Unit Area Connection (ENSTAR/APC Metering Stations 500 & 505)

                                       61
<PAGE>

            At the upstream flange of the Buyer's master meter located at or
            near the inlet of the Buyer's Kenai-Anchorage pipeline in Section
            30, Township 5 North, Range 11 West, Kenai Peninsula Borough, Seward
            Meridian, State of Alaska.

      b.    CIGGS Pipeline Connection (ENSTAR/APC Metering Station 209)

            At the upstream flange of the Buyer's meter at or near the
            connection of the Buyer's Royalty Pipeline and the CIGGS pipeline
            located in the Northeast 1/4 of the Northeast 1/4 of Section 21,
            Township 7 North, Range 12 West, Kenai Peninsula Borough, Seward
            Meridian, State of Alaska.

      c.    KNPL Pipeline Connection (ENSTAR/APC Metering Station 413)

            At the upstream flange of the Buyer's meter at or near the
            connection of the Buyer's Royalty Pipeline and the Kenai-Nikiski
            pipeline located in the Northeast 1/4 of the Northeast 1/4 of
            Section 21, Township 7 North, Range 12 West, Kenai Peninsula
            Borough, Seward Meridian, State of Alaska.

                                       62

Source: [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00099-of-00352.parquet"}, [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00099-of-00352.parquet"}]]