Exhibit 10.2


 


SECOND RESTATED AND AMENDED POWER SALES AGREEMENT
BETWEEN
PACIFICORP
AND
BLACK HILLS CORPORATION
TABLE OF CONTENTS
 


	
   

  	
  Page

  
	
   

  	
   

  
	
  RECITALS

  	
  1

  
	
  Section 1:
   Definitions

  	
  1

  
	
  Section 2:
   Term

  	
  3

  
	
  Section 3:
   Sale and Delivery of Capacity and
  Energy

  	
  4

  
	
  Section 4:
   Scheduling

  	
  6

  
	
  Section 5:
   Prices and Payments

  	
  7

  
	
  Section 6:
   Governmental Regulation

  	
  9

  
	
  Section 7:
   FERC Reporting; Past Audit Issues

  	
  10

  
	
  Section 8:
   Arbitration

  	
  10

  
	
  Section 9:
   Uncontrollable Forces

  	
  11

  
	
  Section 10:
   Notices

  	
  12

  
	
  Section 11:
   Waiver

  	
  13

  
	
  Section 12:
   Several Obligations

  	
  13

  
	
  Section 13:
   Amendments

  	
  13

  
	
  Section 14:
   Assignment

  	
  13

  
	
  Section 15:
   Choice of Law

  	
  13

  
	
  Section 16:
   Replacement of Original Agreement

  	
  13

  



 
Appendix A - Annual Fixed Cost
Appendix B - Variable Costs
 
SECOND RESTATED AND AMENDED POWER SALES AGREEMENT
BETWEEN
PACIFICORP
AND
BLACK HILLS CORPORATION


 

















 


This Second Restated and Amended Power Sales Agreement, dated as of the 29th day of September, 1997 (“Agreement”), is entered into by and between PacifiCorp (“PacifiCorp”), an Oregon corporation, and Black Hills Power and Light Company, predecessor to Black Hills Corporation (“Black Hills”), a South Dakota corporation.  PacifiCorp and Black Hills are referredto herein individually as “Party” and collectively as “Parties”.
 
RECITALS
 
WHEREAS, on December 31, 1983, Black Hills and Pacific Power & Light Company (a predecessor to PacifiCorp) entered into a Power Sales Agreement which was modified by a letter agreement between the Parties dated August 31, 1995 (“Original Agreement”); and
 
WHEREAS, the Parties desire to further restate and amend the Original Agreement as modified as of the Effective Date of this Agreement; and
 
WHEREAS, this Agreement will supersede and replace the Restated and Amended Power Sales Agreement dated February 7, 1997 which had never become effective;
 
NOW, therefore, the Parties agree as follows:
 
Section 1:   Definitions
 
As used in this Agreement, the following terms shall have the following meanings:
 
1.1  ”Adjusted Variable Cost Rate” is the cost for energy as defined and adjusted in Appendix B, Section 1.
 
1.2  “Agreement” is this Second Restated and Amended Power Sales Agreement,together with the Appendices A through C, attached hereto.
 
1.3  “Annual Fixed Costs” are the costs for capacity as determined pursuant to Appendix A to this Agreement.
 
1.4  “Black Hills’ System” is Black Hills’ entire electric power generating and transmission system as it exists from time to time.


 


1

















 


1.5  ”Colstrip Project” is PacifiCorp’s share in Unit Nos.  3 and 4 of the coal-fired electric generating plant near Colstrip, Montana.
 
1.6  “Effective Date” is 0000 hours Mountain prevailing time August 1, 1997.
 
1.7  “FERC” is the Federal Energy Regulatory Commission of the United States.
 
1.8  “Net Colstrip Generation” is PacifiCorp’s combined share of the output of the Colstrip Project Unit Nos.  3 and 4 generation.  Net Colstrip Generation, when expressed as capacity, shall, for purposes of this Agreement, be deemed to be 150 megawatts (“MW”).  When expressed as energy, Net Colstrip Generation is the actual energy production less station service requirements and less generator step-up transformer losses expressed in megawatt-hours (“MWh”) as reported in PacifiCorp’s FERC Form No.  1.
 
1.9  “Original Agreement” is the Power Sale Agreement between Black Hills and PacifiCorp dated December 31, 1983 as amended by the letter agreement dated August 31, 1995.
 
1.10  “Original Investment” shall be that dollar amount specified in Subsection A.2.1 of Appendix A to this Agreement.
 
1.11  “PacifiCorp’s System” is PacifiCorp’s entire electric power generating and transmission system as it exists from time to time.
 
1.12  “Prudent Utility Practice” is, at any particular time, either any of the practices, methods, and acts engaged in or approved by a significant portion of the electrical utility industry prior thereto or any of the practices, methods, or acts which, in the exercise of reasonable judgment the light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with reliability, safety,


 


2

















 


and expedition.  Prudent Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others but, rather, to be a spectrum of possible practices, methods, or acts.  Prudent Utility Practice shall also include those practices, methods, and acts that are required by applicable laws and final orders or regulations of regulatory agencies having jurisdiction; provided, that the definition of Prudent Utility Practice shall not be construed to allow regulatory bodies to amend the fixed formulae used to determine prices under this Agreement, nor any other provision of this Agreement.  Prudent Utility Practice shall not be interpreted as justification for discriminating among customers, including Black Hills.
 
1.13  “Transmission Losses” are the product of the system energy scheduled by Black Hills multiplied by the applicable real time transmission loss factor pursuant to the Transmission Tariff.
 
1.14  “Transmission Tariff” is PacifiCorp’s FERC pro forma open access tariff on file with FERC as PacifiCorp’s FERC Electric Tariff, Original Volume No.  11, as such may be amended or replaced from time to time.
 
1.15  “Variable Cost Rate” is the variable cost rate as calculated from the FERC Form No.  1 as demonstrated in Appendix B Sections B2 and B3.
 
1.16  “Western Energy” is the coal company or its successor company through which the Colstrip Project purchases its coal supply and coal transportation.
 
Section 2:   Term
 
2.1  Term.  This Agreement shall become effective on the Effective Date pursuant to Subsection 1.6.  Subject to the provisions of Section 2.2, it shall terminate on December 31, 2023.
 
2.2  Regulatory Approval.  PacifiCorp, at its expense, shall file this


 


3

















 


Agreement with the Federal Energy Regulatory Commission (FERC) as provided for in Subsection 6.1.  PacifiCorp shall provide Black Hills with a copy of the filing prior to its submittal to the FERC.  Black Hills shall file with the FERC an intervention in support of PacifiCorp’s filing of this Agreement.  Upon FERC’s acceptance of this Agreement, the Original Agreement shall terminate as of the Effective Date.  If the FERC does not accept or approve this Agreement and the transmission service agreements under the Transmission Tariff for filing in toto, the Parties shall exercise best efforts to amend these agreements to comply with the FERC action in a manner consistent with the Parties’ original intent.  Failure of the FERC to accept or approve these agreements after the Parties have exercised best efforts shall terminate these agreements, and the Original Agreement shall remain in full force and effect.
 
Section 3:   Sale and Delivery of Capacity and Energy
 
3.1  Sale of Capacity.  For the term of this Agreement, PacifiCorp shall sell, and Black Hills shall purchase, system capacity as shown below:
 


	
   

  	
   

  	
  Capacity

  	
   

  
	
   

  	
   

  	
  Amount

  	
   

  
	
  Commencing

  	
   

  	
  MW

  	
   

  
	
  Effective Date

  	
   

  	
  75

  	
   

  
	
  January 1, 2000

  	
   

  	
  70

  	
   

  
	
  January 1, 2001

  	
   

  	
  65

  	
   

  
	
  January 1, 2002

  	
   

  	
  60

  	
   

  
	
  January 1, 2003

  	
   

  	
  55

  	
   

  
	
  January 1, 2004

  	
   

  	
  50

  	
   

  



 
3.2  Minimum Energy Purchases.  Each month Black Hills shall purchase a minimum of 22,500 MWh of system energy multiplied by the applicable capacity pursuant to subsection 3.1 and divided by 75 MW.
 
3.3  Points of Delivery.  PacifiCorp shall provide system power and energy purchased under this Agreement to Black Hills under the terms and conditions of separate service agreements under the Transmission Tariff.  Black Hills shall cause such service agreements to be executed with PacifiCorp to reserve the amount of transmission capacity and the type of


 


4

















 


service which in Black Hills’ determination is required for the amount of capacity purchased pursuant to Subsection 3.1 and Black Hills shall pay separately for such transmission wheeling charges and shall be responsible for either the return of energy or the payment for applicable energy charges for transmission losses under the Transmission Tariff.  However, the merchant function of PacifiCorp shall purchase any capacity requirements for losses, Spinning Reserve Service, Supplemental Reserve Service and any other required ancillary service on behalf of Black Hills at the expense of the merchant function of PacifiCorp.  In addition, the merchant function of PacifiCorp shall provide Black Hills with non-firm transmission service on PacifiCorp’s transmission system for deliveries to the Wyodak Substation from PacifiCorp’s multiple generation units as defined in such service agreements for transfers not to exceed 5 megawatt-hours per hour for all hours from the Effective Date through the earlier of the termination of Black Hills’ Power Integration Agreement with Montana-Dakota Utilities Company dated September 9, 1994 or December 31, 2006.  Black Hills shall use its best efforts in scheduling transmission services under such service agreements so as to minimize its use of the nonfirm transmission service to be made available by the merchant function of PacifiCorp.  Black Hills shall be responsible for any amounts of additional firm transmission service or nonfirm service in excess of the amount made available to Black Hills by the merchant function of PacifiCorp pursuant to the terms of the Transmission Tariff.  On a monthly basis Black Hills may purchase energy in addition to that energy associated with the capacity purchases under Subsection 3.1, at the Adjusted Variable Rate applicable for such month, under the terms of this Agreement to replace the Transmission Losses required under the Transmission Tariff pursuant to Subsections 4.1 and 4.2.


 


5

















 


3.4  Deliveries.  PacifiCorp does now and will continue to maintain available transmission facilities sufficient to meet its delivery obligations under this Agreement for the Term hereof.
 
Section 4:   Scheduling
 
4.1  Amounts of Capacity and Energy.  Commencing on the Effective Date of this Agreement, and continuing during the Term hereof, PacifiCorp shall make available from PacifiCorp’s System, and Black Hills shall schedule, energy associated with purchased capacity;provided, that PacifiCorp shall not be obligated under this Agreement to schedule and deliver energy toBlack Hills in excess of the following amounts plus Transmission Losses if elected by Black Hills pursuant to Subsection 4.2:
 


	
  Hourly

  	
  —

  	
  75
  MWh multiplied by the applicable purchased capacity ofSubsection 3.1 and
  divided by 75 MW.

  
	
  Weekly

  	
  —

  	
  10,050
  MWh multiplied by the applicable purchased capacity of Subsection 3.1 and
  divided by 75 MW.

  
	
  Monthly

  	
  —

  	
  One hundred ten percent
  (110%) of the estimated monthly energy under Section 4.2.

  



 
4.2  Estimated Monthly Energy.  At least five (5) days prior to the commencement of each month, Black Hills shall deliver to PacifiCorp by facsimile a written estimate of expected energy purchases for the following month.  Such estimate of expected energy purchases shall not be less than the minimum monthly requirement pursuant to Subsection 3.2.  Included in the written estimate Black Hills shall notify PacifiCorp if Black Hills elects to purchase or not purchase the Transmission Losses under this Agreement for such month.
 
4.3  Schedules.  Black Hills shall preschedule all deliveries of power and energy purchased under this Agreement no later than 1000 hours Pacific prevailing time on each workday prior to the day of such schedule and in


 


6

















 


accordance with normal scheduling practices.  Such schedules of power and energy shall be deemed to be delivered during the hours and in the amounts scheduled; provied, that if scheduled deliveries are interrupted due to forces beyond either Party’s control, including but not limited to loss of facilities, such scheduled deliveries shall be adjusted to reflect such interruptions.
 
4.4  Limitations on Variations.  Black Hills shall use its best efforts, consistent with Prudent Utility Practice, to minimize rapid changes in deliveries hereunder; provided, that, unless otherwise agreed, the hour-to-hour variation in such scheduled deliveries shall be limited to 25 MWh per hour.
 
Section 5:   Prices and Payments.
 
5.1  Annual Fixed Cost Payments.  Beginning on the Effective Date and continuing until December 31, 1999, by the fifteenth (15th) of each month Black Hills shall pay PacifiCorp one-twelfth of the Annual Fixed Cost of $164.59 per kW-yr.  multiplied by the capacity purchased pursuant to Subsection 3.1.Commencing on January 14, 2000, and by the fifteenth (15) of each month thereafter, Black Hills shall pay PacifiCorp one-twelfth (1/12) of the Annual Fixed Cost as determined pursuant to Appendix A, multiplied by the capacity purchased pursuant to Subsection 3.1.  Black Hills’ last and final Annual Fixed Cost payment for the Original Investment shall be December 15, 2018 pursuant to Appendix A.  The last and final Annual Fixed Cost payment for each of the associated subsequent annual levelized fixed charge for capital additions, replacements and betterments shall be after the completion of the 35th year of Annual Fixed Cost payments for the associated subsequent capital addition.  For example, the final Annual Fixed Cost Payment for 1986 subsequent capital additions, replacements and betterments shall be December 15, 2021.


 


7

















 


5.2  Annual Fixed Cost Payment Reduction.  For the invoices for each month of the calendar years 2000 through 2009, the amount calculated pursuant to Subsection 5.1 shall be reduced by $95,564, irrespective of the reduced sale of capacity pursuant to Subsection 3.1.
 
5.3  Adjusted Variable Cost Payments.
 
5.3  Adjusted Variable Cost Payments for Estimated Energy.  By the fifteenth (15th) of each month after the Effective Date, Black Hills shall pay PacifiCorp an amount determined by multiplying the Adjusted Variable Cost Rate, as expressed in dollars per MWh ($/MWh), by the estimated monthly MWh of energy including any elected Transmission Losses as provided under Subsection 4.2.
 
5.3.1  Monthly Adjustments.  PacifiCorp shall use the following formula to calculate an adjustment to each prior month’s invoice to adjust for actual versus estimated monthly usage:
 


	
   

  	
  z
  =

  	
  [(a
  - b) x (c)] (1 +i)

  
	
   

  	
   

  
	
  Where

  	
  z
  =

  	
  the
  amount of charge to Black Hills (if positive) or credit to Black Hills (if
  negative);

  
	
   

  	
   

  	
   

  
	
   

  	
  a
  =

  	
  the
  minimum energy pursuant to Subsection 3.2 or the actual energy scheduled for
  the prior month in MWh (whichever is greater) including any energy scheduled
  for elected Transmission Losses;

  
	
   

  	
   

  	
   

  
	
   

  	
  b
  =

  	
  the
  energy which was billed for such prior month, in MWh, including any
  Transmission Losses pursuant to Subsection 4.2;

  
	
   

  	
   

  	
   

  
	
   

  	
  c
  =

  	
  the
  applicable Adjusted Variable Cost Rate in dollars per MWh ($/Mwh) for such
  prior month;

  
	
   

  	
   

  	
   

  
	
   

  	
  i
  =

  	
  the
  prime interest rate, expressed in decimal form on an annual basis, as
  established by the 

  
				



 


8

















 


	
   

  	
   

  	
  Morgan Guaranty Trust
  Company of New York as of the first day of the prior month, divided by twelve
  (12).

  



 


5.4  Payment Schedules.  PacifiCorp shall send by facsimile to Black Hills an invoice for all services hereunder, by the third (3rd) working day of each month.  Black Hills shall pay such invoices by the fifteenth (15th) of such month.  Each monthly payment shall be made in immediately available funds by the due date.  Such payments to PacifiCorp shall be electronically wire transferred to:
 
The First National Bank of Chicago
A.B.A.  No.  071000013
PacifiCorp-Wholesale & Trans.
Account No.  55-44688
 
Simple interest shall accrue on any amount not paid when due at a rate of one hundred twenty-five percent (125%) of the prime rate as established by the Morgan Guaranty Trust Company of New York during the period of delinquency.
 
5.5  Operation of the Colstrip Project.  It is the intent of the Parties that the pricing provisions of this Section 5 shall account for all operational variables of the Colstrip Project.  Subject to exceptions as specified in this Agreement, the pricing for the delivery of PacifiCorp system power to Black Hills is based upon PacifiCorp’s cost of ownership and operation of the Colstrip as provided in this Section 5.  Nothing in this Agreement shall be construed as an obligation for PacifiCorp to dispatch or control the Colstrip Project in any particular fashion.
 
Section 6:   Governmental Regulation
 
6.1  Filing.  The Parties shall submit this Agreement for filing to the FERC no later than October 15, 1997.  PacifiCorp shall seek a waiver of any FERC rules that require an earlier filing date.
 
6.2  Fixed-Formulae Contract.  The terms, conditions, and formulae for


 


9












 
prices for service specified herein shall remain in effect for the term hereof, and shall not be subject to change through application to the FERC pursuant to the provisions of Section 205 of the Federal Power Act absent the agreement of the Parties hereto.  The Parties covenant that neither shall request relief from any of the provisions of this Agreement pursuant to the provisions of Section 206 of the Federal Power Act absent the agreement of the Parties hereto.  The foregoing statutory references are intended to include any subsequent similar enactments.
 
Section 7:   FERC Reporting:  Past Audit Issues.
 
7.1  Reporting.  For purposes of administering this Agreement, data reported in PacifiCorp’s FERC Form No.  1 shall be deemed to be accurate for purposes of calculating the Variable Cost Rate and the Adjusted Variable Cost Rate; provided, however, should the FERC as a result of an audit, require changes to PacifiCorp’s FERC Form No.  1 that are relevant to the calculation of the Variable Cost Rate or the Adjusted Variable Cost Rate, the billings to Black Hills shall be retroactively adjusted to reflect such changes.  PacifiCorp shall fully comply with the Uniform System of Accounts as promulgated by the FERC from time to time in the preparation of the Form No. 1 during the Term of this Agreement.
 
7.2  Past Audit Issues.  It is agreed by the Parties that any and all outstanding audit issues are resolved by this Agreement.  Any outstanding audit questions or requests for information from Black Hills to PacifiCorp are deemed to be withdrawn and satisfied.
 
7.3  Past Billings.  All prior invoices under the Original Agreement are deemed to be correct and not subject to further audit or adjustment unless mutually agreed by the Parties.
 
Section 8:   Arbitration
 
If any dispute arises under this Agreement as to any factual matter,


 


10

















 


the Parties shall submit the factual dispute to a board of three arbiters, one to be selected by each Party and the Parties to agree on the selection of a third arbiter.  If the Parties are unable to agree on the third arbiter, the Parties shall request the senior district judge of the United States District Court of the District of Wyoming to submit a list of five (5) persons.  Each Party shall alternately strike one name from the list, the first exercise to be determined by lot.  The last person remaining on the list shall serve as the third (3rd) arbiter.  Except as otherwise set forth herein, the arbitration shall be held under the rules of the American Arbitration Association.  The arbiters shall render their decision in writing not later than thirty (30) days after the matter has been submitted to them, and the decision of a majority of the board of arbiters of the factual dispute shall be binding on the Parties.  The arbiters may, in their discretion, award arbitration costs and attorneys’ fees to either Party.
 
Section 9:   Uncontrollable Forces.
 
Neither Party to this Agreement shall be considered to be in default in performance of any obligation hereunder if failure of performance shall be due to uncontrollable forces.  The term “uncontrollable forces” means any cause beyond the control of the Party affected, including, but not limited to, failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor disturbance sabotage, and restraint by court order or public authority, which by exercise of due foresight such Party could not reasonably have been expected to avoid, and which by exercise of due diligence it shall be unable to overcome.  A Party shall not, however, be relieved of liability for failure of performance if such failure be due to causes arising out of its own negligence or to removable or remediable causes which it fails to remove or remedy with reasonable dispatch.  Any Party rendered


 


11

















 


unable to fulfill any obligation by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch.  Nothing contained herein, however, shall be construed to require a Party to prevent or settle a strike against its will.  It is specifically understood and agreed that PacifiCorp’s delivery of capacity and energy to Black Hills under this Agreement comes from PacifiCorp’s System and shall not depend upon the existence, operation, or efficiency of the Colstrip Project alone.  In determining any uncontrollable force justifying any nonperformance by PacifiCorp herein, the entire PacifiCorp System shall be taken into consideration.
 
Section 10:   Notices.
 
Any notice, demand, or request provided for in this Agreement shall be deemed properly served, given, or made if delivered in person or sent by facsimile and registered or certified mail, postage paid and return receipt requested, to the person so designated as its authorized representative.  The titles and addresses of the authorizedrepresentatives hereunder are as follows:
 


	
  For
  Black Hills:

  	
  Vice President, Finance

  
	
   

  	
  Black Hills Corporation

  
	
   

  	
  625 Ninth Street

  
	
   

  	
  P.O.  Box 1400

  
	
   

  	
  Rapid City, South Dakota
  57709

  
	
   

  	
  Fax No.:  (605) 342-0945

  
	
   

  	
   

  
	
  For
  PacifiCorp:

  	
  Vice President, Global
  Energy

  
	
   

  	
  Trading &
  Wholesale Sales

  
	
   

  	
  PacifiCorp,
  Suite 1600

  
	
   

  	
  700 NE Multnomah

  
	
   

  	
  Portland, Oregon
  97232-4194

  
	
   

  	
  Fax No.:  (503) 731-2160

  
	
   

  	
   

  
	
  With
  a copy to:

  	
  Manager, Contract
  Administration

  
	
   

  	
  PacifiCorp, Suite 625

  
	
   

  	
  825 NE Multnomah

  
	
   

  	
  Portland, OR 97232-2153

  
	
   

  	
  Fax No.  (503) 275-2827

  



 
Either Party may change its authorized representative by providing notice to the other Party pursuant to this Section 10.


 


12

















 


Section 11:   Waiver


 


Any waiver by a Party of its rights with respect to default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed to be a waiver with respect to any subsequent default or matter.  No delay in asserting or enforcing any right hereunder shall be deemed a waiver of such fight.
 
Section 12:   Several Obligations.
 
Except where specifically stated in this Agreement to be otherwise, the duties, obligations, and liabilities of the Parties are intended to be several and not joint or collective.  Nothing contained in this Agreement shall ever be construed to create an association, trust, partnership, or joint venture or to impose a trust or partnership duty, obligation, or liability on or with regard to either Party.  Each Party shall be individually and severally liable for its own obligations under this Agreement.
 
Section 13:   Amendments.
 
No amendment of this Agreement shall be effective without written approval of each Party.
 
Section 14:   Assignment.
 
This Agreement shall not be assigned by any Party to any third party without the written consent of the other Party, and such consent shall not be withheld unreasonably.  No assignment of this Agreement shall operate to discharge the assignor of any duty or obligation hereunder without the written consent of the other Party.
 
Section 15:   Choice of Law
 
This Agreement shall be subject to and be construed under the laws of the State of Wyoming.
 
Section 16:   Replacement of Original Agreement.
 
This Agreement represents the entire agreement of the Parties and


 


13

















 


replaces the Original Agreement in its entirety, except as provided in Subsection 2.2.
 
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed in their respective names by their respective officers thereunder duly authorized.
 


	
   

  	
  PACIFICORP

  
	
   

  	
   

  
	
   

  	
  By:

  	
   

  
	
   

  	
  Vice President

  
	
   

  	
  Date:  September 29, 1997

  
	
   

  	
   

  
	
   

  	
   

  
	
   

  	
  BLACK HILLS CORPORATION

  
	
   

  	
   

  
	
   

  	
   

  
	
   

  	
  By:

  	
   

  
	
   

  	
  Vice President

  
	
   

  	
   

  
	
   

  	
  Date:

  	
   

  
				



 
Appendix A
 
APPENDIX A:  ANNUAL FIXED COSTS
 
Introduction
 
This Appendix A sets forth the elements and techniques to calculate the Annual Fixed Cost under Subsection 5.1 for the term of the Agreement.
 
The Annual Fixed Cost is the dollars per megawatt sum of:  (a) initial levelized annual fixed cost, (b) subsequent levelized annual fixed costs for Colstrip Plant investments made through December 31, 1996, and (c) other fixed annual charges, including but not limited to property taxes, insurance, and taxes other than income tax.
 
Prior to January 1, 2000 the Annual Fixed Cost shall be those as set forth in Subsection 5.1.  Commencing on January 1, 2000 the Annual Fixed Cost shall be calculated as set forth in


 


14

















 


this Appendix A.  Capital additions, replacements, and betterments made after December 31, 1996 shall not be included for calculating the Annual Fixed Cost.  During the balance of the Term, PacifiCorp shall continue to comply with generally accepted accounting principles in identifying capital additions, replacements and betterments to the Colstrip Project and capitalizing such for book purposes as opposed to expensing them and including them in the Variable Cost Rate calculation.
 
Section A1.   Discussion of Methodology
 
A1.1  Levelized fixed charges are the basis of annual fixed costs hereunder.  While actual capital-related charges associated with an investment may vary considerably from year to year, the levelized fixed charge translates these charges into a level annual amount which remains constant over time.  The present values of the two streams (varying versus constant) are equal.
 
A1.2  The levelized fixed charge includes three basic components:  (a) return on investment, given a specific capital structure and cost of capital; (b) recovery of investment, given the appropriate depreciation period related to the investment; and (c) income tax requirements, given tax law considerations.  These components are commonly expressed as:  (a) interest expense on debt and return required by shareholders; (b) book depreciation; and, (c) income taxes incorporating the effects of investment tax credits and tax depreciation.
 
A1.3  An initial levelized annual charge rate shall be applied to the original investment of Colstrip Project Unit Nos.  3 and 4.  The rate shall be recalculated effective each January 1 only in the event of a change during the preceding calendar year in any of the following: (a) the capital structure; (b) cost of long-term debt; (c) preferred retum; (d) the return on common equity; or, (e) income tax law, but not to be applied retroactively.
 
A1.4  Subsequent levelized annual fixed charge rates shall


 


15

















 


be calculated each year through December 31, 1996 to reflect the most current information and shall be applied each year to the amount of capital additions, replacements (less credit for net salvage and insurance proceeds, if any) and betterments of the Colstrip Project completed through the end of the preceding calendar year.
 
Section A2:   Determination of Annual Fixed Costs
 
The Annual Fixed Costs for any year shall be determined by (a) adding the amounts calculated under Sections A2.1 through A2.5, and (b) dividing the total by Net Colstrip Generation in MW.  The costs referred to above are:
 
A2.1  The initial levelized annual fixed charge computed as the product of (1) PacifiCorp’s initial levelized annual fixed charge rate determined annually in accordance with Section AS of this Appendix A, and (2) PacifiCorp’s total Original Investment in the Colstrip Unit Nos.  3 and 4 of $194,965,667.  Black Hills shall pay no initial levelized annual fixed costs aver 2018, pursuant to Subsection 5.1.
 
A2.2  The total subsequent an nual levelized fixed charge shall be computed as the sum of annual charges determined by the product of (a) PacifiCorp’s subsequent levelized annual fixed charge rate, as calculated using the then current applicable cost of capital in accordance with Section A3 of this Appendix A and (b) the subsequent dollar investment in capital additions, replacements (less credit for net salvage and insurance proceeds, if any), and betterments of the Colstrip Project, completed for each year from January 1, 1986 through December 31, 1996.
 
A2.3  All ad valorem taxes imposed upon the Colstrip Project by governmental agencies without limitation for excluded subsequent capital additions, replacements, and betterments.
 
A2 4  All taxes, assessments, payments in lieu of taxes, or other charges imposed by any governmental body assessed or charged


 


16

















 


against PacifiCorp relating to the Colstrip Project, excluding ad valorem taxes, state and federal income taxes and excluding any tax included in the Variable Cost Rate calculation of Subsection B3.  It is understood that the current Montana electric energy license tax is included in the Variable Cost Rate.
 
A2.4  Insurance premiums which shall be deemed to be $322,941.08 (0.16 percent of the Colstrip production plant investment as of December 31, 1996).
 
Section A3:   Elements of Levelized Annual Fixed Charge Rates
 
A3.1  Capital Structure:
 
A3.1.1  Commencing January 1, 2000, for purposes of calculating the initial levelized annual fixed charge rate and subsequent levelized fixed charge rates in any year, PacifiCorp’s then-current FERC approved capital structure as described further in Subsection A3.3 shall be utilized.  Such capital structure shall be updated as provided for in Section A3.3.  The capital structure approved by the FERC the date of execution of this Agreement is as follows:
 


	
   

  	
   

  	
  Percent

  	
   

  
	
  Long-Term Debt

  	
   

  	
  45.54

  	
  %

  
	
  Preferred Stock

  	
   

  	
  8.40

  	
  %

  
	
  Common Equity

  	
   

  	
  46.06

  	
  %

  
	
  Total Capital

  	
   

  	
  100

  	
  %

  



 
A3.2  Cost of Capital:
 
A3.2.1  Long-Term Debt:  Commencing on January 1, 2000, the long-term debt applicable in the calculation of the initial and subsequent levelized annual fixed charge rates shall be equal to PacifiCorp’s then-current weighted average cost of longterm debt calculated using FERC prescribed methods.  As of the execution date of this Agreement, this rate is 7.11%.  The cost of long-term debt shall be updated as provided for in Subsection A3.3, below.
 
A3.2.2Preferred Stock:  Commencing on January 1, 2000, the return on preferred stock applicable in the calculation of initial and subsequent levelized annual fixed charge rates shall be PacifiCorp’s then-current weighted average cost of


 


17

















 


preferred stock calculated using FERC prescribed methods.  As of the execution date of this Agreement, this rate is 6.76%.  The cost of preferred stock shall be updated as provided for in Subsection A3.3, below.
 
A3.2.3   Common Stock Equity:  Commencing on January 1, 2000, the return on common stock equity applicable in the calculation of each initial levelized annual fixed charge rate, and each subsequent levelized annual fixed charge rate, shall be the then current FERC approved cost of common equity for PacifiCorp.  The current cost of common stock equity approved by the FERC at the date of execution of this Agreement is 10.40%.  The cost of common stock equity shall be updated as provided for in Subsection A3.3 below.
 
A3.3Updates to FERC-Based Elements of Fixed Charge Rates:  At such times, subsequent to January 1, 2000, as new FERC orders establish a different capital structure, cost of long-term debt, cost of preferred stock or cost of common equity for PacifiCorp, or PacifiCorp enters into a settlement of a FERC rate proceeding where FERC staff reports known as “top sheets” provide for such differences, effective the following January 1, such different capital structure, cost of long-term debt, cost of preferred stock or cost of common equity shall be substituted in Subsections A3.1 through A3.2 as appropriate until the next FERC order or settlement.  If more than three years have elapsed between the Effective Date of this Agreement and a FERC order or settlement (with FERC staff top sheets), or between FERC orders and/or settlements (with FERC staff top sheets) establishing a capital structure, cost of long-term debt, cost of preferred stock or cost of common equity, either Party may cause PacifiCorp to promptly apply to the FERC for an order establishing a current capital structure, cost of long-term debt, cost of preferred stock and cost of common equity and the FERC findings shall be substituted effective the January 1 following an order resulting 


 


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from such application.
 
A3.4  Book Depreciation:  Book Depreciation charges shall be at a straight-line rate based on a thirty-five (35) year life in calculating the initial and subsequent levelized annual fixed charge rate.
 
A3.5  Income Tax Requirements:  Income tax requirements applicable in calculating both initial and subsequent levelized annual fixed charge rates shall be based on the following items:  provided, subsequent changes in tax laws shall be incorporated in computing levelized annual fixed charge rates for periods following such tax law changes:
 
A3.5.1  The actual federal corporate income tax rate beginning at 46% in 1984, and tracking the actual corporate tax and projected tax rates for the life of the investment, with tax rate at the execution date of this Agreement at 35%.
 
A3.5.2  A state corporate income tax rate equal to the estimated composite weighted average of PacifiCorp’s three-factor formula for unitary allocation of state taxable income based upon payroll, property, and revenue in each state in which PacifiCorp provides retail service.  As of the execution date of this Agreement, the rate is four and four-tenths percent (4.4%).
 
A3.5.3  Use of 1 5-year depreciation under Accelerated Cost Recovery System for original investment and additions prior to 1987, and 20-year depreciation under Modified Accelerated Cost Recovery System for additions beginning in 1987 through 1996.
 
A3.5.4  Regular investment tax credits allowed in accordance with the provisions of the Internal Revenue Code of 1954, as amended, regardless of whether PacifiCorp is able to use such credits.  The investment tax credit in calculating the initial levelized annual fixed charge rate shall be deemed to be 9.65 percent of tax basis.
 
A3.5.5  Tax basis shall be 75.98% of the book basis in calculating each initial levelized annual fixed charge rate, and


 


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100% of the book basis in calculating each subsequent levelized annual fixed charge rate.
 
A3.5.6  The annual income tax amount included in the levelized annual fixed charge rate shall be calculated utilizing the methodology demonstrated in Item 3 of Appendix C of this Agreement.
 
Appendix B
 
APPENDIX B: VARIABLE COSTS
 
This Appendix B sets forth the elements and techniques to calculate the Adjusted Variable Cost Rate and the Variable Cost Rate under Subsection 5.3 for each year of this Agreement.
 
Section B1:   Adjusted Variable Cost Rate
 
During the term of this Agreement, the Adjusted Variable Cost Rate expressed in dollars per megawatt-hour ($/MWh) in any year shall be determined by June 1 of each year, to be effective from such June 1 to May 31 of the following calendar year.  The Adjusted Variable Cost Rate for any year shall be the prior year’s Adjusted Variable Cost Rate multiplied by the ratio of the prior calendar year’s Variable Cost Rate, divided by the Variable Cost Rate as determined one calendar year earlier.  (The Variable Cost Rate shall be determined pursuant to Section B2.) The calculation of the Adjusted Variable Cost Rate is as follows:
 
AVCn=AVCn-1 *(VCmost recent year /VCmost recent year -1)
Where: AVC = Adjusted Variable Cost Rate
VC = Variable Cost Rate
n = current year
 
For example, the Adjusted Variable Cost Rate effective June 1, 2000 is equal to the Adjusted Variable Cost Rate effective June 1, 1999 multiplied by the Variable Cost Rate based on 1999 FERC Form No.  1 and divided by the Variable Cost Rate based on 1998 FERC Form No.  1.
 
The initial Adjusted Variable Cost Rate shall be deemed to be $12.20/MWh and shall be effective through May 31, 1998.  This


 


20

















 


Adjusted Variable Cost Rate shall be adjusted each successive year beginning June 1, 1998 pursuant to this Section B1.
 
Section B2:   Variable Cost Rate
 
During the term of this Agreement, the prior calendar year’s Variable Cost Rate ($/MWh) shall be determined by June 1 of each year.  The Variable Cost Rate for each year shall be calculated from PacifiCorp’s FERC Form No.  1 for the Colstrip Project as illustrated in Section B3.  The FERC Form No.  1 costs shall be adjusted to spread the fixed portion of PacifiCorp’s fuel costs over the greater of (1) the actual PacifiCorp Net Colstrip Generation (MWh) or (2) the generation based on a deemed 150 MW of capacity at an 80% capacity factor.  The commodity component of the fuel costs shall be a separate calculation using actual Net Colstrip Generation (MWh).  The non-fuel variable cost shall be computed using the generation based on a deemed 150 MW of capacity at an 80% capacity factor.
 
Secoption B3:   Variable Cost Rate Calculation
 
B3.1  An example calculation is shown in Subsection B3.2.  The input data for the calculation is from PacifiCorp’s 1996 FERC Form No.  1 for the Colstrip Project and the sum of the Western Energy fixed charges (line 9 of Subsection B3.2) for contract coal and coal transportation paid in such calendar year.  The 1996 Variable Cost Rate is $13.12 pursuant to Subsection B3.2.
 
B3.2  Variable Cost Rate Calculation - 1996 Example


 


	
  1

  	
  1996 PacifiCorp Colstrip Project

  
	
  2

  	
  Annual Variables

  
	
  3

  	
   

  	
  Calendar Year

  	
  1996

  	
   

  
	
  4

  	
   

  	
  PacifiCorp
  FERC Form No.1 (“Form 1”) Page No.

  	
   

  	
  403.1

  	
   

  
	
  5

  	
   

  	
  Form 1,
  line 33, “Total Production Expenses”

  	
   

  	
  $

  	
  11,619,595

  	
   

  
	
  6

  	
   

  	
  Form 1,
  line 19, “Fuel”

  	
   

  	
  $

  	
  7,594,943

  	
   

  
	
  7

  	
   

  	
  Form 1,
  line 12, “Net Generation, Exclusive of Plant Use”, MWh

  	
   

  	
  795,052

  	
   

  
	
  8

  	
   

  	
  Hours
  in the Year (Leap Year)

  	
   

  	
  8784

  	
   

  



 


21

















 


	
  9

  	
   

  	
  Sum of Western Energy Fixed Charges for Contract
  Coal and Coal Transportation

  	
   

  	
  $

  	
  567,744

  	
   

  
	
  10

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  11

  	
   

  	
  Non–Fuel Variable Cost Component

  	
   

  	
   

  	
   

  
	
  12

  	
   

  	
  Non–fuel Production Expense (line 5-line 6)

  	
   

  	
  $

  	
  4,024,652

  	
   

  
	
  13

  	
   

  	
  Deemed Non–Fuel Variable Adjustment Factor
  (Electrical energy license tax and A&G)

  	
   

  	
  1.03

  	
   

  
	
  14

  	
   

  	
  Black Hills Adjusted Non–Fuel Variable Cost (line
  12 x line 13)

  	
   

  	
  $

  	
  4,145,392

  	
   

  
	
  15

  	
   

  	
  Deemed Production for Non–Fuel Calculation (150 MW
  @ 80% OF), MWh

  	
   

  	
  1,054,080

  	
   

  
	
  16

  	
   

  	
  Non–Fuel Variable Cost, S/MWh (line 14/line 15)

  	
   

  	
  3.93

  	
   

  
	
  17

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  18

  	
   

  	
  Fuel Cost–Fixed Component

  	
   

  	
   

  	
   

  
	
  19

  	
   

  	
  Western Energy Fixed Charges (line 9)

  	
   

  	
  $

  	
  567,744

  	
   

  
	
  20

  	
   

  	
  Deemed Production for FKed–Fuel Calculation, MWh

  	
   

  	
  1,054,080

  	
   

  
	
  21

  	
   

  	
  (greater of 150MW @ 80% CF or line 7)

  	
   

  	
   

  	
   

  
	
  22

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  23

  	
   

  	
  Fuel – Fixed Cost, $/MWh (line 19/line 20)

  	
   

  	
  0.54

  	
   

  
	
  24

  	
   

  	
  Fuel Cost – Commodity Component

  	
   

  	
   

  	
   

  
	
  25

  	
   

  	
  Fuel Production Expense (line 6)

  	
   

  	
  $

  	
  7,594,943

  	
   

  
	
  26

  	
   

  	
  Deemed Fuel Variable Adjustment Factor

  	
   

  	
  0.98

  	
   

  
	
  27

  	
   

  	
  Black Hills Adjusted Fuel Expense (line 24 x line
  25)

  	
   

  	
  $

  	
  7,443.044

  	
   

  
	
  25

  	
   

  	
  Western Energy Feed Charges (line 9)

  	
   

  	
  $

  	
  567,744

  	
   

  
	
  28

  	
   

  	
  Black Hills Fuel Commodity Expenses (line 26– line
  27)

  	
   

  	
  $

  	
  6,875.300

  	
   

  
	
  29

  	
   

  	
  Net Generation, MWh (line 7)

  	
   

  	
  795,052

  	
   

  
	
  30

  	
   

  	
  Fuel Commodity cost, $/MWh (line 28/line 29)

  	
   

  	
  8.65

  	
   

  
	
  31

  	
   

  	
   

  	
   

  	
   

  	
   

  
	
  32

  	
   

  	
  1996 Variable
  Cost Rate, $/MWh (line 16+ line 21+ line 30)

  	
   

  	
  13.12

  	
   

  



 
Section B4:   Unavailability of Colstrip Variable Costs
 
B4  In years in which the capacity factor of Colstrip Unit Nos.  3 and 4 together is less than forty percent (40%), or if


 


22

















 


Colstrip Project costs are not available for any reason, or if PacifiCorp is no longer a participant in the Colstrip Project, the Adjusted Variable Cost Rate shall not be updated for up to a year after its normal adjustment period.  During such time the Parties shall negotiate an appropriate alternative variable cost methodology.  If the Parties are unable to agree, the issue of the variable cost methodology shall be submitted to arbitration based on the fair market price for long term fuel and O&M for a project similar to Colstrip.  For the purpose herein, a “project similar to Colstrip” is a project located in the western part of the United States consisting of a generating station of two or more coal-fired steam electric generators of 500 megawatts or larger operating at an eighty percent (80%) load factor or more and situated in close proximity to a surface coal mine from which the generators are fueled.  The Annual Fixed Costs shall not be modified by such an event.


 


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