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(a) If a lessee or an affiliate transports qualified gas under an arm's length contract, the transportation allowance used to determine the monthly value of the lessee's qualified gas must be the actual and reasonable costs incurred and paid by the lessee or an affiliate and not refunded to the lessee or the affiliate for transportation, less any costs disallowed under 11 AAC 25.060 - 11 AAC 25.090 or 11 AAC 25.160 - 11 AAC 25.220. To claim a transportation allowance under this section, the lessee shall demonstrate that the contract is arm's length.

(b) If the commissioner determines that the consideration set out in an arm's length contract exceeds the consideration actually transferred either directly or indirectly from the lessee or an affiliate to the transportation entity for the transportation, the commissioner may require that the transportation allowance be reduced or redetermined under 11 AAC 25.180 - 11 AAC 25.200.

(c) If the commissioner determines that the consideration paid under an arm's length transportation contract exceeds the reasonable value of the transportation because of misconduct by the contracting parties, or because the lessee breached a duty to the state to market the production for the mutual benefit of the lessee and the state, the commissioner may require that the transportation allowance be reduced or redetermined under 11 AAC 25.180 - 11 AAC 25.200.

History: Eff. 5/29/2010, Register 194

Authority: AS 38.05.020

AS 38.05.180

AS 43.90.310

11 AAC 25.180. Transportation contracts not at arm's length - Alaska mainline and Canada mainline

(a) If a lessee, its marketing affiliate, or any affiliate other than a transportation affiliate transports qualified gas on the Alaska mainline or Canada mainline and that pipeline is a transportation affiliate, the cost of transportation must be the allowable actual and reasonable cost, as determined under (b) - (m) of this section, 11 AAC 25.160, and 11 AAC 25.210, of transportation provided by the pipeline that is the transportation affiliate. However, if the circumstances described in (n) of this section occur, the amount determined under that subsection must be used as the cost of transportation.

(b) If calculating allowable actual and reasonable cost in accordance with (b) - (m) of this section, the lessee, without regard to whether a pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC), and except as provided in (c) - (m) of this section, shall calculate that cost in accordance with the FERC Cost-of-Service Rates Manual, dated June 1999, the FERC Order Issuing Clarification and Granting Rehearing in Southern Natural Gas Co., 130 FERC Para. 61,193 (Docket nos. CP09-36-002, CP09-40-001, and AD10-3-000, March 18, 2010), and the FERC Order Granting Rehearing in Florida Gas Transmission Co., 130 FERC Para. 61,194 (Docket nos. CP09-17-001, AC08-161-002, and AD10-3-000, March 18, 2010). The FERC documents listed in this subsection are adopted by reference for purposes of this section, except as provided in (c) - (m) of this section.

(c) The cost of transportation under (b) - (m) of this section is determined by first identifying the term of years and profile for capital recovery in the transportation services agreement under which qualified gas is shipped. If those terms match the terms offered in the plan for conducting an open season for the Alaska mainline, the negotiated rate generated by those terms under the plan for conducting an open season for the Alaska mainline, as modified under (b) and (d) - (m) of this section, is the cost of transportation used to calculate the transportation allowance, unless the negotiated rate generated under the plan for conducting an open season for the Alaska mainline, as modified under (b) and (d) - (m) of this section, is greater than the amount determined under (n) of this section, in which case the amount determined under (n) of this section is the cost of transportation.

(d) If the transportation services agreement under which the qualified gas is shipped does not set out a profile for capital recovery, or sets out a term of years and profile for capital recovery other than one offered in the plan for conducting an open season for the Alaska mainline, depreciation must be calculated to recover capital investment over the economic life of the pipeline, and must be calculated using annual composite depreciation percentages that result in levelized rates over the life of the transportation services agreement and that recover that part of total capital investment that is the greater of 4/5 or the percentage that equals the ratio of the original term of years in the transportation services agreement to the economic life of the pipeline. In this calculation, the economic life must be the estimated useful life used to calculate the initial recourse rate for the pipeline.

(e) In the absence of long-term debt actually issued for the Alaska mainline or Canada mainline, as applicable, a lessee shall compute the return on the part of the capital investment treated as financed with long-term debt using the weighted average of the cost of long-term debt for the proxy group designated by the department under 11 AAC 25.190(j) . After the commencement of commercial operations of the Alaska mainline or Canada mainline, as applicable, at least 75 percent of the capital investment must be treated as financed with long-term debt, unless the applicable transportation services agreement provides for a higher percentage debt, in which case the higher percentage must be used.

(f) Capital investment must be the properly allocable part of the lower of capital investment

(1) that would be properly reportable on FERC Form 2 if the pipeline were subject to FERC jurisdiction;

(2) that is prudently incurred, as determined by the regulatory agency with jurisdiction over the pipeline; or

(3) allowed under the applicable transportation services agreement.

(g) A change in ownership of an asset does not alter the original cost valuation of capital investment.

(h) An allowance for funds used during construction (AFUDC) must be calculated consistent with the FERC Cost-of-Service Rates Manual adopted by reference in (b) of this section, except to the extent modified by this section. AFUDC begins to accrue no earlier than the time certificate pre-filing commences under 18 C.F.R. 157.21(e). AFUDC must be compounded annually, and not more frequently. For purposes of determining AFUDC, 70 percent of the capital investment must be treated as financed with long-term debt for the period before the commencement of commercial operations of the Alaska mainline or Canada mainline, as applicable, unless the applicable transportation services agreement provides for a higher percentage debt, in which case the higher percentage must be used.

(i) An allowance for the cost to dismantle and remove the pipeline and for restoration after removal of the pipeline may be taken only if specifically identified and approved by the regulatory agency with jurisdiction over the pipeline in an applicable tariff for the pipeline.

(j) Tax depreciation used to calculate accumulated deferred income taxes for the Alaska mainline is seven years for all depreciable property, consistent with 26 U.S.C. 168. Tax depreciation used to calculate accumulated deferred income taxes for the Canada mainline is the terms of years set out in the federal income tax laws of Canada for depreciation of pipeline property.

(k) Operating and maintenance expenses may not include ad valorem taxes or any other cost otherwise recoverable under (b) and (d) - (m) of this section. Operating and maintenance expenses must be the properly allocable part of the lower of operating and maintenance expenses

(1) that would be properly reportable on FERC Form 2 if the pipeline were subject to FERC jurisdiction;

(2) that are prudently incurred, as determined by the regulatory agency with jurisdiction over the pipeline; or

(3) allowed under the applicable transportation services agreement.

(l) Except for refunds and surcharges permitted by the regulatory agency with jurisdiction over the pipeline, an adjustment may not be made for recoveries in the prior period that exceed or are less than the transportation affiliate's allowable actual and reasonable cost as determined under (c) - (i) of this section.

(m) Per-unit transportation costs for transportation of qualified gas by a transportation affiliate must be based on a 100 percent load factor of certificated capacity even if the capacity is not used at a 100 percent load factor.

(n) If the cost of transportation calculated under (b) - (m) of this section is greater than the amount the lessee or its affiliate actually pays for transportation, the amount actually paid and not the cost of transportation calculated under (b) - (m) of this section shall be used by the lessee in calculating the monthly value of the state's royalty share of qualified gas.

(o) In this section, "plan for conducting an open season for the Alaska mainline" means the original plan as filed by TransCanada Alaska Company, LLC with FERC in Docket No. PF09-11-001 on January 29, 2010.

History: Eff. 5/29/2010, Register 194

Authority: AS 38.05.020

AS 38.05.180

AS 43.90.310

11 AAC 25.190. Transportation contracts not at arm's length - pipelines other than the Alaska mainline and Canada mainline

(a) If a lessee, its marketing affiliate, or any affiliate other than a transportation affiliate transports qualified gas on a pipeline other than the Alaska mainline or Canada mainline and that pipeline is a transportation affiliate, the cost of transportation must be the allowable actual and reasonable cost, as determined under (b) - (n) of this section, 11 AAC 25.160, and 11 AAC 25.210, of transportation provided by the pipeline that is the transportation affiliate. However, if the circumstances described in (o) of this section occur, the amount determined under that subsection must be used as the cost of transportation.

(b) If calculating allowable actual and reasonable cost in accordance with (b) - (n) of this section, the lessee, without regard to whether a pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC), and except as provided in (c) - (n) of this section, shall calculate that cost in accordance with the FERC Cost-of-Service Rates Manual, dated June 1999, the FERC Order Issuing Clarification and Granting Rehearing in Southern Natural Gas Co., 130 FERC Para. 61,193 (Docket nos. CP09-36-002, CP09-40-001, and AD10-3-000, March 18, 2010), and the FERC Order Granting Rehearing in Florida Gas Transmission Co., 130 FERC Para. 61,194 (Docket nos. CP09-17-001, AC08-161-002, and AD10-3-000, March 18, 2010). The FERC documents listed in this subsection are adopted by reference for purposes of this section, except as provided in (c) - (n) of this section.

(c) The applicable costs of transportation are determined for a calendar year by calculating the total amount for the year for the following items and allocating that total, as provided under this section, to the qualified gas:

(1) an allowance for operating and maintenance expenses of the pipeline;

(2) annual depreciation on capital investment in the pipeline at original cost;

(3) annual amortization of allowance for funds used during construction (AFUDC);

(4) an after-tax return on the sum of capital investment in the pipeline at original cost net of depreciation accumulated before the year of calculation, and AFUDC net of cumulative AFUDC amortized before the year of calculation, with the undepreciated capital investment and unamortized AFUDC balances adjusted to account for accumulated deferred income taxes and retirements; a return may not be earned on cash working capital;

(5) income tax on the equity part of the return on capital investment under (4) of this subsection;

(6) ad valorem taxes on the pipeline;

(7) if specifically identified and approved in an applicable tariff for a regulated pipeline, an allowance for the cost to dismantle and remove the pipeline and for restoration after removal of the pipeline.

(d) For purposes of determining the allowance described in (c)(1) of this section, the proper allocation of operating and maintenance expenses must be determined with reference to whether the applicable transportation services agreement requires rolled-in or incremental rate treatment. Operating and maintenance expenses may not include ad valorem taxes or any other cost otherwise recoverable under (c)(2) - (7) of this section. Operating and maintenance expenses must be the properly allocable portion of the lower of operating and maintenance expenses

(1) that would be properly reportable on FERC Form 2 if the pipeline were subject to FERC jurisdiction;

(2) that are prudently incurred, as determined by the regulatory agency with jurisdiction over the pipeline; or

(3) allowed under the applicable transportation services agreement.

(e) For purposes of (c)(2), (4), and (5) and (h) of this section,

(1) capital investment must be the properly allocable part of the lower of capital investment

(A) that would be properly reportable on FERC Form 2 if the pipeline were subject to FERC jurisdiction;

(B) that is prudently incurred, as determined by the regulatory agency with jurisdiction over the pipeline; or

(C) allowed under the applicable transportation services agreement;

(2) the proper allocation of capital investment must be determined with reference to whether the applicable transportation services agreement requires rolled-in or incremental rate treatment; and

(3) a change in ownership of an asset does not alter the original cost valuation of capital investment.

(f) AFUDC used to determine the items described in (c)(3) and (4) of this section must be calculated consistent with the FERC Cost-of-Service Rates Manual, adopted by reference in (b) of this section,

(1) with AFUDC being accrued beginning at the time that certificate pre-filing, if required under 18 C.F.R. 157.21, commences under 18 C.F.R. 157.21(e), or if pre-filing is not required, at the time that filing of an application for a FERC certificate of public convenience and necessity is accepted under 18 C.F.R. 157.8; and

(2) using the weighted average cost of capital determined in accordance with (i) and (j) of this section, and annual compounding.

(g) For purposes of determining annual depreciation and annual amortization of AFUDC under (c)(2) and (3) of this section, depreciation and amortization must be calculated using the same term of years and same profile for capital recovery used in the transportation services agreement under which qualified gas is shipped. However, if the transportation services agreement does not set out a profile for capital recovery, or establishes a depreciation schedule that recovers total capital before the conclusion of the pipeline's economic life as determined in the initial proceeding for a FERC certificate of public convenience and necessity, depreciation must be calculated to recover capital investment over the economic life of the pipeline, and must be calculated using annual composite depreciation percentages that recover an equal percentage of original plant investment each year. In this calculation the economic life must be the estimated useful life used to calculate the initial recourse rate for the pipeline, or the pipeline's initial generally prevailing rate if a recourse rate is not offered. A change in ownership of an asset does not alter the depreciation schedule, or the accumulated deferred income taxes, established by the original owner of the pipeline when annual depreciation and annual amortization of AFUDC is determined under (c)(2) and (3) of this section. A capital investment may be depreciated only once, and may not be depreciated below a reasonable salvage value. If specifically identified and provided for in an applicable tariff for a regulated pipeline, the salvage value may be negative, unless the calculation of costs under (c) of this section includes an allowance under (c)(7) of this section for dismantlement and removal of the pipeline and restoration after removal of the pipeline.

(h) For pipelines that are regulated either by FERC or the Regulatory Commission of Alaska, accumulated deferred income taxes will be calculated consistent with the FERC Cost-of-Service Rates Manual, adopted by reference in (b) of this section, using the tax depreciation schedule established by the relevant taxing authority for pipeline assets and the book depreciation schedule established under (g) of this section.

(i) For purposes of determining the return on capital investment for a gas pipeline under (c)(4) of this section, the percentage of the capital investment treated as financed with long-term debt is the percentage actually used by the pipeline owner to finance the pipeline or 70 percent, whichever amount is greater. The remainder is treated as financed with equity. The return on the portion of the capital investment treated as financed with long-term debt is the actual cost, if any, of the debt or, in the absence of actual cost, the return computed by the department using the weighted average of the cost of long-term debt for the proxy group designated by the department under (j) of this section.

(j) For purposes of (c)(4) of this section, an after-tax rate of return on the percentage of the capital investment treated as financed with equity will be determined by the department for a calendar year. The department will use a two-stage discounted cash flow model to determine the return on capital investment in a pipeline. In implementing that model, the department will give substantial weight to the FERC Policy Statement in Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, Docket No. PL07-2-000, dated April 17, 2008 and adopted by reference for that purpose, subject to the following:

(1) the department will designate the group of proxy companies from companies that meet the following criteria:

(A) the company is publicly traded;

(B) the company is a natural gas pipeline company;

(C) the company and its shares are recognized and tracked by Value Line or a similar investment information service;

(D) pipeline operations constitute a high proportion of the company's business;

(E) the company or its predecessor in interest has been in operation for at least three years;

(F) there are estimates by Institutional Brokers Estimate System (I/B/E/S) established by Thomson Reuters, or similar widely available, reliable estimates, of five-year earnings growth for the company;

(G) the company has a history of paying dividends or distributions and is currently paying a dividend or distribution;

(H) the company has not eliminated or announced an intention to eliminate its dividend or distribution;

(2) in determining whether a company meeting the criteria under (1) of this subsection should be included in the group of proxy companies, the department may consider the following factors:

(A) the size of the company's market capitalization;

(B) the company's credit rating;

(C) whether four or more companies have already been selected for inclusion in the proxy group of companies;

(3) the department will calculate the rate of return for a calendar year based on information about the group of proxy companies for a recent 12-month period selected by the department.

(k) For purposes of (c)(5) of this section, the

(1) combined federal and state income tax rate for the year of calculation must be used for a pipeline located within the United States;

(2) applicable combined foreign income tax rate for the year of calculation must be used for a pipeline located in another country.

(l) The amounts described in (c)(1) and (5) - (7) of this section must be calculated for every calendar year on the same basis, which may be either

(1) the amounts incurred during, or applicable to, the calendar year of calculation; or

(2) if the pipeline was

(A) in operation for at least nine months during the calendar year immediately preceding the calendar year of calculation, the amounts incurred during, or applicable to, that immediately preceding calendar year; the amounts are annualized or prorated if necessary to account, respectively, for the pipeline's being in operation for less than that entire immediately preceding calendar year or less than the entire calendar year of calculation; or

(B) not in operation for at least nine months during the calendar year immediately preceding the calendar year of calculation, good-faith estimates of the amounts that will be incurred during, or will be applicable to, the calendar year of calculation; an overestimate or underestimate is deducted from or added to, respectively, the amounts used for the next calendar year.

(m) To allocate the total amount for the items set out in (c) of this section to a specific quantity of qualified gas,

(1) per-unit transportation cost is based on contracted capacity or throughput during the royalty reporting period for the pipeline as a whole, whichever amount is greater, unless the pipeline commences commercial operations after issuance of a certificate of public convenience and necessity for the Alaska mainline, in which case per-unit transportation cost is based on a 100 percent load factor of certificated capacity;

(2) the costs of different categories of pipeline transportation services bear the same relationship to one another as under the recourse rates in the applicable tariff, unless the department determines that the relationship under the applicable tariff is unreasonable, in which case the department will allocate costs among different categories of pipeline transportation services;

(3) the costs of pipeline transportation between different pairs of receipt and delivery points bear the same relationship to one another as under the recourse rates in the applicable tariff, unless the department determines that the relationship under the applicable tariff is unreasonable, in which case the department will allocate costs to pipeline transportation between different pairs of receipt and delivery points.

(n) A management fee is not an allowable cost of transportation for the purpose of calculating a transportation affiliate's allowable actual and reasonable costs of transportation under this section.

(o) If the cost of transportation as calculated under (b) - (n) of this section is greater than the negotiated rate for transportation available to a lessee or its affiliate, the negotiated rate and not the cost of transportation as calculated under (b) - (n) of this section must be used in calculating the monthly value of the state's royalty share of qualified gas.

History: Eff. 5/29/2010, Register 194

Authority: AS 38.05.020

AS 38.05.180

AS 43.90.310

Editor's note: Value Line is published by Value Line, Inc., 220 East 42nd Street, New York, NY 10017. Value Line's website address is www.valueline.com.

11 AAC 25.200. Transportation contracts not at arm's length - LNG transportation

(a) If a lessee, its marketing affiliate, or any affiliate other than a transportation affiliate transports qualified gas using an LNG transportation affiliate, transportation costs must be the LNG transportation affiliate's allowable actual and reasonable costs incurred between the outlet of a liquefaction plant and the inlet of a regasification plant, as those costs are determined under (b) - (l) of this section, 11 AAC 25.160, and 11 AAC 25.210. However, if 11 AAC 25.160(b) applies, the amount determined under 11 AAC 25.160(b) must be used for transportation costs.

(b) For purposes of (a) of this section, the applicable costs of transportation are

(1) an allowance for operating and maintenance expense;

(2) annual depreciation on capital investment;

(3) a return on capital investment; and

(4) positioning costs, amortized over 36 months.

(c) For purposes of (b)(1) of this section, the allowance for operating and maintenance expense is the amount of expense actually incurred that is the direct cost of operation and maintenance attributable to a lessee's qualified gas.

(d) For purposes of (b)(2) and (3) of this section, a cost of capital allowance that consists of depreciation and a return on invested capital will be allowed.

(e) For purposes of (b)(2) and (3) of this section, depreciation and a return on capital investment must be calculated using the methodology set out in the Department of Revenue publication Computation of a Cost-of-Capital Allowance under 15 AAC 55.196, Incorporating Depreciation and Return on Invested Capital for Marine Vessels and Improvements, Second Edition, dated September 19, 2003; that publication is adopted by reference except as follows:

(1) the methodology is applied as if the term "vessel" read "LNG pipeline or tanker";

(2) the useful life for purposes of the methodology is 30 years;

(3) the weighted average cost of capital is 0.2 percentage point greater than that otherwise calculated under the methodology.

(f) A cost of capital allowance under this section for a vessel will be allowed only for days when the vessel is in allowable service, in allowable lay up, or in allowable dry dock as provided in (g) of this section.

(g) For purposes of this section,

(1) a vessel is in allowable service if the vessel is

(A) in service within the meaning given in 15 AAC 55.900, unless the vessel is in dry dock; or

(B) idle for a period of fewer than 90 consecutive days immediately before operation in allowable service under (A) of this paragraph; for purposes of this subparagraph, a vessel is not idle if it is in dry dock;

(2) a vessel is laid up if it is idle for a period of 90 or more consecutive days; for purposes of this paragraph, a vessel is not idle if it is in dry dock;

(3) a vessel is in allowable lay up if the vessel is laid up during a calendar year, but only to the extent that the total number of days it is or has been laid up while owned or effectively owned by the lessee or its affiliate through the end of that calendar year does not exceed the total number of days it is or has been in allowable service while owned or effectively owned by the lessee or its affiliate through the end of that calendar year;

(4) a vessel is in allowable dry dock if the vessel is in dry dock during a calendar year, but only for that fraction of the total days in dry dock that equals the sum of the number of days during the year that the vessel is in allowable service and the number of days during the year that the vessel is in allowable lay up, divided by the sum of the number of days during the year that the vessel is in allowable service, the number of days during the year that the vessel is laid up, and the number of days during the year that the vessel is in alternative service;

(5) a vessel is in alternative service if it is not in lay up, dry dock, or allowable service; and

(6) if necessary to determine a vessel's status during a month, the vessel's status at later times will be considered.

(h) The following requirements apply to the timing of changes in vessel status:

(1) a vessel changing from operation in allowable service to lay up or operation in alterative service begins lay up or operation in alternative service on the day after the last day of cargo discharge in allowable service;

(2) a vessel changing from operation in alternative service to lay up or operation in allowable service begins lay up or operation in allowable service on the day after the last day of cargo discharge in alternative service;

(3) a vessel changing from lay up to operation in allowable service or operation in alternative service begins operation in allowable service or operation in alternative service on the day after the vessel departs from the location where the vessel was laid up;

(4) a vessel going into dry dock begins dry dock status on the day after the last day of cargo discharge or, if going into dry dock from lay up, on the day after the vessel departs from the location where the vessel was laid up;

(5) a vessel finishing dry dock changes from dry dock status to the immediately subsequent status on the day after the vessel departs the dry dock facility;

(6) a vessel begins operation in allowable service on the day that its useful life begins or, in the case of a used vessel newly acquired by a lessee or its affiliate, on the day that its remaining useful life for that lessee or its affiliate begins, if the vessel proceeds directly to enter operation in allowable service; otherwise, the vessel begins operation in alternative service on the day specified in this paragraph; for purposes of this paragraph, the beginning of a vessel's useful life or remaining useful life is determined in accordance with generally accepted accounting principles.

(i) Allowable voyage and port costs for a vessel are costs actually incurred for the following purposes:

(1) fuel for the vessel while in port and at sea not to exceed the actual cost if purchased from a third party, or if the fuel is not purchased from a third party, the spot market price of comparable fuel as reported in the latest Platt's Oilgram Price Report published on or before the date of the fuel purchase for the market nearest the point of refueling, plus related allowable fuel taxes and handling charges;

(2) stores and provisions for the vessel and its captain and crew;

(3) wages and benefits of the vessel's captain and crew;

(4) routine maintenance;

(5) drydocking costs, expensed in the year paid;

(6) port and dock fees;

(7) demurrage;

(8) tug and pilotage fees;

(9) marine agents' fees in port;

(10) lightering;

(11) transshipment charges;

(12) customs fees and duties;

(13) taxes incurred due to the ownership and operation of the vessel, except for income taxes and other taxes (including certain franchise taxes) measured by income;

(14) regular and customary gratuities that are also legal;

(15) insurance premiums actually paid to third-party insurers;

(16) loading and unloading inspection fees;

(17) a reasonable management fee for operating a vessel; this fee is set at six percent of the allowable costs set out in (1) - (3) of this subsection; this set fee covers all general and administrative costs related to vessel operations, including all costs for accounting services, clerical services, administrative services, secretarial services, data processing services, legal services, corporate and operations management, overhead pass-throughs, facility costs and depreciation, corporate planning, risk management, environmental planning and risk evaluation, public affairs, governmental affairs, political affairs, dues and subscriptions, long-range scheduling, and long-range planning; additional deductions will not be allowed for these costs;

(18) other costs directly associated with the operation or maintenance of a vessel, including costs for port services and operations, cargo scheduling and planning, fleet staffing, fleet scheduling, fleet staff training, fleet safety, engineering for repair, engineering for maintenance, engineering for drydocking, quality assurance for vessel operations, communication systems, navigation systems, United States Coast Guard certifications, and utility services; these costs include costs for personnel performing the functions listed and the first level of supervision of these personnel.

(j) For purposes of this section, allowable voyage and port costs for a vessel do not include taxes or fees on the receipt of LNG at a marine terminal from a vessel.

(k) The lessee's actual or reasonable marine transportation cost, as otherwise determined under this section, for a lessee that transports gas produced in the state through a charter, contract of affreightment, sublease, or other arrangement on behalf of a person not affiliated with the lessee, in addition to the cost of transporting the lessee's own gas produced in the state, includes the cost of transporting that non-affiliated person's gas produced in the state and is reduced by the revenue received by the lessee for providing that transportation.

(l) In this section, "positioning cost" includes the cost borne by the lessee for placing an LNG tanker into position before the LNG tanker's first voyage in service for that lessee.

History: Eff. 5/29/2010, Register 194

Authority: AS 38.05.020

AS 38.05.180

AS 43.90.310

Editor's note: Platt's Oilgram Price Report is published by McGraw-Hill, Inc., 1221 Avenue of the Americas, New York, New York 10020.

11 AAC 25.210. Non-allowable transportation costs

(a) A lessee may not include the following costs in calculating an arm's length transportation allowance under 11 AAC 25.170 or a non-arm's length transportation allowance under 11 AAC 25.180 - 11 AAC 25.200:

(1) the cost of transportation of qualified gas downstream of destination;

(2) the cost of transportation of residue gas or gas plant products after processing of qualified gas is complete at destination;

(3) a cost or fee incurred for storage, except that a lessee may deduct

(A) a charge by a pipeline for storage for no more than 30 days if the storage is required under the applicable transportation services agreement and is necessary for pipeline operations;

(B) a cost or fee for the storage as part of LNG transportation, if the fee or cost is allowed under 11 AAC 25.200;

(4) an intra-hub transfer fee paid to a pipeline hub operator for administrative services, including accounting for the sale of qualified gas within a hub and title transfer tracking;

(5) a fee paid to a scheduling service provider;

(6) internal costs to schedule, nominate, and account for the sale or movement of qualified gas, if incurred by a lessee or its affiliate other than a transportation affiliate; those costs include salaries and related costs, rent and space costs, office equipment costs, and legal fees;

(7) an aggregator or marketer fee, including a fee a lessee or its affiliate pays an affiliate or another person to market, purchase, or resell qualified gas, or find or maintain a market for qualified gas;

(8) a fee paid to a broker, including a fee paid to a person that arranges marketing or transportation;

(9) a penalty incurred as a shipper, including

(A) an over-delivery cash-out penalty, including the difference between the price the pipeline pays for over-delivered volumes outside the tolerances and the price received for over-delivered volumes within the tolerances;

(B) a scheduling penalty, including a penalty incurred for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;

(C) an imbalance penalty, including a penalty incurred for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;

(D) an operational penalty, including fees incurred for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline;

(10) the cost of pipeline transportation within the unit of production, unless

(A) the pipeline is regulated by FERC or the Regulatory Commission of Alaska; or

(B) for Prudhoe Bay gas covered by the 1980 Prudhoe Bay Royalty Settlement Agreement, the cost is allowed under that agreement;

(11) the cost of pipeline transportation within a state unit other than the unit of production where the gas was reinjected into a reservoir, unless

(A) the pipeline is regulated by FERC or the Regulatory Commission of Alaska; or

(B) for Prudhoe Bay gas covered by the 1980 Prudhoe Bay Royalty Settlement Agreement, the cost is allowed under that agreement;

(12) the cost of a gathering pipeline or a pipeline in the state that is not subject to regulation by FERC or the Regulatory Commission of Alaska;

(13) as provided in 11 AAC 25.070(d) , the cost of transporting carbon dioxide in a pipeline upstream of the Alaska mainline in excess of quantities allowed in the specification of conditions for acceptance into the Alaska mainline;

(14) the cost of transporting a gas or associated substance that is not royalty-bearing, except that lessees may include in a transportation allowance the costs of transporting carbon dioxide in quantities not to exceed the quantities allowed in the specification of conditions for acceptance into the Alaska mainline;

(15) other costs a lessee incurs for services it is required to provide at no cost to the state as lessor or otherwise;

(16) costs of arbitration, litigation, or other dispute resolution activity that involves the state or concerns the rights or obligations

(A) among owners of a transportation entity; or

(B) between an owner of a transportation entity and a shipper.

(b) In addition to the costs set out in (a) of this section, a lessee may not include the following costs in determining a non-arm's length transportation allowance under 11 AAC 25.180 - 11 AAC 25.200:

(1) payments, either volumetric or in value, for actual or theoretical losses of qualified gas;

(2) costs of a surety.

History: Eff. 5/29/2010, Register 194

Authority: AS 38.05.020

AS 38.05.180

AS 43.90.310

11 AAC 25.220. Unused capacity deduction

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