Gas Sales Agreement between Union Oil Company of California and Alaska Pipeline Company

EX-10.24 7 k02906exv10w24.txt GAS SALES AGREEMENT BETWEEN UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY EXHIBIT 10.24 GAS SALES AGREEMENT BETWEEN UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY EFFECTIVE DATE NOVEMBER 17, 2000 TABLE OF CONTENTS

i 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

ii 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

iii 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

iv 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; 1 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 "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, 3 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 "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 "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 "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 "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 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, 9 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 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 11 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: 12 (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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 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 ###-###-#### Telephone: (907 ###-###-#### Facsimile: (907 ###-###-#### 38 For Payments: Attention: Accounts Receivable Address: Physical: 909 West Ninth Avenue Anchorage, AK 99501 Mailing: P.O. Box 196247 Anchorage, AK ###-###-#### 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 ###-###-#### 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 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 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 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 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 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 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 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 HYPOTHETICAL BUYER'S FORECAST FOR OCTOBER 1, 2003
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 ----- ----- ----- ----- ------ ---- ---- ----- ----- ----- 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 ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
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 FIRST HYPOTHETICAL SELLER'S FORECAST FOR OCTOBER 10, 2003
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- 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 ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
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 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 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
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- 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 ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
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 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 EXHIBIT C TO THE GAS SALES AGREEMENT BETWEEN UNION OIL COMPANY OF CALIFORNIA AND ALASKA PIPELINE COMPANY BUYER'S TEN YEAR FORECAST
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 ----- ----- ----- ----- ----- ---- ----- ----- ----- ----- 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 ===== ===== ===== ===== ===== ===== ===== ===== ===== =====
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 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 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.
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- 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
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 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 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 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 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 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 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 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 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