Administrative Law Judge Bruce H. Johnson (the ALJ) held an evidentiary hearing in this matter before on September 17, 2009, at the Public Utilities Commission, 350 Metro Square Building, 121 Seventh Place East, St. Paul, Minnesota.

The parties to this proceeding are: ALLETE Corporation d/b/a Minnesota Power Company (“Minnesota Power,” “MP,” or the “Company”); the Minnesota Department of Commerce/Office of Energy Security (the “OES”); the Large Power Intervenors (“LPI”); and NextEra Energy Resources, LLC (“NextEra”).

Christopher Anderson, Associate General Counsel, ALLETE, Inc., 30 West Superior Street, Duluth, Minnesota 55802; and David R. Moeller, Attorney, ALLETE, Inc., 30 West Superior Street, Duluth, Minnesota 55802, appeared on behalf of the Applicant Minnesota Power.

Linda Jensen Assistant Attorney General, 445 Minnesota Street, 1400 Bremer Tower, St. Paul, Minnesota 55101 appeared on behalf of the OES.

Robert S. Lee and Andrew P. Moratzka, Attorneys at Law, Mackall, Crounse & Moore, PLC, 1400 AT&T Tower, 901 Marquette Avenue, Minneapolis, Minnesota 55402-2859, appeared on behalf of the LPI.

Christine Brusven and Todd Guerrero, Fredrikson & Byron, 200 South Sixth Street, Suite 4000, Minneapolis, MN 55402-1425, appeared on behalf of NextEra.

Commission staff members Clark Kaml and Chris Fittipaldi, Financial Analysts appeared on behalf of the MPUC Staff.

The Commission will make the final determination of the matter after the expiration of the period for filing exceptions as set forth above, or after oral argument, if such is requested and had in the matter.

FINDINGS AND CONCLUSIONS

I. SUMMARY OF ISSUES, FINDINGS, AND CONCLUSIONS

In its Notice and Order for Hearing dated July 1, 2009, the Commission directed the ALJ and the parties to this contested case proceeding to specifically address the following issues, among others, relating to Minnesota Power’s May 14, 2009, Petition to Purchase Square Butte Cooperative’s Transmission Assets and for Restructuring Power Purchase Agreements from Milton R. Young Unit 2 Generating Station

(1) Is the volume of renewable energy supplies potentially movable over the direct-current line proportional to the need for renewable resources?

(2) Are the transactions the Company proposes - the purchase of the direct current line, the winding-down of the contract with the Milton R. Young Unit 2, and the addition of both purchased and Company-owned wind power - the least-cost method of meeting its obligations under the Renewable Energy Standard?

(3) Will the capacity of the direct-current line significantly exceed the capacity required to meet the Renewable Energy Standard and, if so, how should the line's "excess capacity" be treated?

(4) Are the transactions proposed by the Company reasonable and prudent?

(5) Does the proposed purchase of the direct-current line meet the public interest standard set forth in Minn. Stat. § 216B.50?

The Commission also directed the ALJ and the parties to analyze the proposed transactions under the factors set forth in Minn. R. 7843.0400, subp. 4, and Minn. R. 7843.0500, subp. 3. As set forth below, the ALJ has also analyzed the proposed transactions under factors set forth in Minn. Stat. § 216B.16, subd. 7c (a), that appear pertinent to the proposed transactions.

The record in this matter shows that the volume of renewable energy potentially movable over the DC Line is proportional to Minnesota Power’s need. The proposed Transactions[1] are the least-cost method for Minnesota Power to meet its renewable energy standard obligations. With some adjustment, the proposed Transactions are reasonable and prudent and in the public interest. With the modifications recommended in this Report, the ALJ recommends that the Commission approve the Transactions because they are consistent with the public interest.

FINDINGS OF FACT

I. GENERAL BACKGROUND

A. Procedural History

1. Square Butte Cooperative (“Square Butte”) currently owns the Milton R. Young Unit 2 lignite coal electric generating station (“Young 2”) and a +/- 250kV direct current transmission line (“DC Line”) that runs between the Square Butte Substation in Center, North Dakota, and Minnesota Power’s Arrowhead Substation near Duluth. Minnkota Power Cooperative (“Minnkota”) operates Young 2. Both Minnesota Power and Minnkota currently have power purchase and sales agreements (PPAs) with Square Butte, which transmits the purchased power to Minnesota Power along the DC Line. Minnesota Power, in turn, retransmits the power purchased by Minnkota back to Minnkota on existing alternating current transmission lines.

2. Minnesota Power, Minnkota, and Square Butte have entered into the series of agreements, executed and delivered as of August 11, 2008,[2] and subsequently amended in a Master Generation Planning Agreement on May 1, 2009.[3] Under those agreements Minnesota Power is seeking to purchase the DC Line from Square Butte; to restructure its PPA with Square Butte to facilitate the gradual reduction of Minnesota Power’s share of the electricity taken from Young 2;[4] and also potentially to replace the Company’s PPA with Square Butte with a PPA with Minnkota in the event Minnkota exercises an option to purchase Young 2 from Square Butte.

3. Commission approval of the Transactions is required under Minn. Stat. § 216B.50 and the Commission’s general regulatory authority.

4. By Petition filed on May 14, 2009, Minnesota Power requested the Commission to approve the Transactions.[5]

5. On July 1, 2009, the Commission issued a Notice and Order for Hearing referring the matter to the Office of Administrative Hearings to conduct a contested case proceeding. At that time, the parties to the proceeding were Minnesota Power and the OES. Minnesota Power notified the Commission that the parties desired to close the Transactions prior the end of the calendar year. The Notice and Order for Hearing expressed willingness to meet that schedule, consistent with developing a proper record and careful decision-making.

6. The ALJ conducted a prehearing conference on July 8, 2009, during which there was agreement on an expedited schedule for prefiling the testimony and for scheduling the hearing, subject to revision as necessary to assure a complete record. The hearing was set to begin on September 17, 2009. On July 17, 2009 the ALJ issued the First Prehearing Order, which memorialized the schedule and addressed other preliminary matters.

7. On August 24, 2009, the Administrative Law Judge issued a Protective Order in this matter.

8. Petitions to intervene were filed by the LPI and NextEra Energy Resources, LLC (NextEra). The ALJ granted those petitions at the hearing. On September 15, 2009, the Izaak Walton League of America, Midwest Office; Wind on the Wires; and the Minnesota Center for Environmental Advocacy (MCEA) submitted a letter of support of Minnesota Power’s application. At the hearing, the ALJ received that letter into the hearing record.

9. The hearing was held on September 17, 2009, as scheduled.

10. Minnesota Power filed its Initial Brief and Proposed Findings of Fact on September 25, 2009. The OES filed its Reply Brief on October 2, 2009. Due to a technical failure, the LPI filed their Reply Brief on October 5, 2009; however, the LPI Reply Brief is accepted as timely. NextEra resources did not submit a post-hearing brief. The hearing record closed on October 5, 2009.

B. Description of Parties and Other Participants

11. Minnesota Power is an operating division of ALLETE, Inc., and is a public utility primarily engaged in the generation, transmission, distribution and sale of electric energy to customers in Minnesota.

12. The Office of Energy Security (OES) represents the interests of Minnesota ratepayers in this proceeding. The OES generally supports approval of the Transactions as being in the public interest. OES has proposed conditions for the protection of Minnesota ratepayers.

13. The LPI are a number of Minnesota Power’s large industrial customers.[6]

14. NextEra is a wholly owned subsidiary of the FPL Group and a wholesale developer, owner, and operator of energy generation systems using resources such as wind, solar, hydroelectric, natural gas, and nuclear. Many of NextEra’s wind facilities are situated in North Dakota, including some of the facilities which are expected to provide electricity to Minnesota Power in the near future. NextEra has taken no position in this proceeding.

15. Minnkota is an electrical generation and transmission cooperative, comprised of a number of member cooperatives, based in Grand Forks, North Dakota. Although a party to the Transactions, Minnkota has not taken an active part in this proceeding.

16. Square Butte is a generation and transmission cooperative headquartered in Grand Forks, North Dakota. Square Butte was incorporated on May 24, 1972 as the vehicle for Minnesota Power and Minnkota to invest in the DC Line. Square Butte has two assets, the DC Line and the 455 MW Young 2 generating plant, which is operated by Minnkota.[7] In 1974, Square Butte entered into a power sales and interconnection agreement with Minnesota Power.[8] That agreement was amended in 1977, with an initial term of 30 years.[9] In 1998, Minnesota Power and Square Butte executed a revised power purchase and sale agreement for a term beginning May 29, 1998, through January 1, 2027 (Revised Minnesota Power PPA) that superseded the 1977 agreement. While a party to the Transactions, Square Butte has also not taken an active part in this proceeding

17. The Izaak Walton League, Fresh Energy, Wind on the Wires, and the Minnesota Center for Environmental Advocacy are environmental interest groups which have participated in a number of proceedings before the Commission. Although not intervening as a party, they submitted a comment letter that has been included in the hearing record as Exhibit 14.

C. Description of the Transmission Line Purchase and Related Agreements

18. The subject of the purchase agreement is the +/- 250kV direct current transmission line (“DC Line”), owned by Square Butte, that runs 465 miles between the Square Butte Substation in Center, North Dakota and Minnesota Power’s Arrowhead Substation near Duluth. The DC Line is one of only five long distance DC transmission lines in the United States. DC transmission lines collectively represent only two percent of all the country’s transmission line miles.[10]

19. The DC Line currently has a capacity of 500MW. All of Young 2’s generation is transferred by the DC Line to the Arrowhead Substation, with Minnkota’s share routed back to Minnkota’s service territory via the AC transmission system.[11]

20. Minnesota Power entered into an agreement with Square Butte for an additional 50MW of DC Line transmission capability that will be made available by 2013 through an equipment upgrade.[12] The volume of energy potentially movable over the DC Line will therefore increase to 550 MW by 2013.[13]

21. Under the Revised Minnesota Power PPA, which was executed in 1998, Minnesota Power purchased entitlement to approximately 71 percent of the Young 2 capacity and energy through January 1, 2027.[14]

22. Beginning in 2006, upon a two-year advance notice to Square Butte and Minnesota Power, Minnkota held options to reduce Minnesota Power’s entitlement by approximately five percent annually, down to a 50 percent share.[15]. As of January 1, 2009, Minnkota exercised all available options; consequently, both Minnkota and Minnesota Power are now limited to 50 percent of Young 2 generation, or approximately 227.5MW each.[16]

23. Since Minnesota Power has no direct ownership interest in Young 2,[17] the Transactions do not include of any Company ownership interest in Young 2. Rather, Minnesota Power will be selling the Company’s right to take a share of the energy and capacity provided by the Young 2 unit under the existing Revised Minnesota Power PPA.[18] Accordingly, Commission regulation of that aspect of the transaction is more properly exercised through the Commission’s general authority rather than through Minn. Stat. § 216B.50.

D. Terms of the Transactions

24. The Asset Purchase Agreement provides for Minnesota Power to purchase Square Butte’s transmission facilities associated with the DC Line for approximately $72 million, subject to post-closing adjustments that will include inventory and Construction Work In Progress (“CWIP”).[19] The Asset Purchase Agreement includes the base agreement executed on August 11, 2008, together with multiple schedules and attachments.[20] Those schedules and attachments list and describe the purchased assets in detail; they also describe the easements that allow Minnesota Power to operate, maintain and replace the Square Butte AC Substation-East facilities and provide the Company with access and the right to operate and maintain the pumps, electrical distribution and other support facilities for the DC Line on the Square Butte Substation.[21]

25. Minnesota Power estimates the cost of purchasing the DC Line at approximately $72 million.[22] The Company initially estimated the net expected benefit of the proposed Transactions for its ratepayers to be $146 million present value (PV).[23] Later direct testimony revised that estimate to a net expected ratepayer benefit of $203 million PV.[24]

26. The Master Generation Planning Agreement is a three-party agreement between Minnesota Power, Minnkota, and Square Butte that was executed on May 1, 2009; it also contains multiple schedules and exhibits.[25]

27. As previously discussed, Minnesota Power and Minnkota each purchase half of the power from Square Butte’s Young 2 station.[26] Minnesota Power also is requesting the Commission’s permission to restructure its existing Revised Minnesota Power PPA with Square Butte to facilitate the gradual reduction of Minnesota Power’s purchase of energy from the Young 2 facility.

28. Under the Master Generation Planning Agreement, Minnesota Power would continue to purchase current levels of Young 2 capacity and energy from Square Butte until the in-service date of Minnkota’s new 345kV AC transmission line.[27] The parties to the agreement are planning for this to occur in 2013.[28] After the in-service date of the Minnkota’s new 345kV transmission line, a new PPA between Minnesota Power and Minnkota (“Minnkota PSA”) would take effect.[29]

29. Until the 345kV line is constructed, Minnesota Power will continue to purchase energy and capacity from Square Butte under its 1998 PPA. Over time, Minnesota Power will sell an increasing amount of that energy and capacity to Minnkota. The specified levels of energy and capacity to be sold under the Minnkota PSA are:

Percentage Entitlement of Net Capability and any Capacity available from Unit #2 above the URGE rating	Megawatts based on 455MW Net Capability	Time Period
17.0329%	77.5 MW	In-Service Date through December 31, 2013
22.5275%	102.5 MW	January 1, 2014 through December 31, 2014
28.0220%	127.5 MW	January 1, 2015 through December 31, 2021
32.4176%	147.5 MW	January 1, 2022 through December 31, 2022
36.8132%	167.5 MW	January 1, 2023 through December 31, 2023
41.2088%	187.5 MW	January 1, 2024 through December 31, 2024
45.6044%	207.5 MW	January 1, 2025 through December 31, 2025
50.0000%	227.5 MW	January 1, 2026 through December 31, 2026

30. However, if Minnkota experiences a delay of the in-service date for its new 345 kV transmission line, Minnesota Power’s sales to Minnkota will correspondingly be delayed.[30]

31. Under the Minnkota PSA, Minnkota will pay Minnesota Power an amount equal to Minnesota Power’s payment to Square Butte of the actual Monthly Charge for Capacity and Energy plus the Annual Capacity Premium.[31] The Annual Capacity Premium will be applied directly to reduce Minnesota Power’s fuel adjustment clause.[32]

32. Also, under the Minnkota PSA, beginning in 2018, Minnkota has the option, with notice (the “Exchange Option”),[33] to require Minnesota Power to convey its existing PPA with Square Butte to Minnkota and to terminate the Minnkota PSA in exchange for a new power purchase and sale agreement (New Minnesota Power PPA).[34]

33. Under the Master Generation Planning Agreement, Square Butte is required to use the proceeds from the sale of the DC Line to redeem taxable Square Butte bonds and pay its make-whole payment, thereby reducing Square Butte’s debt and fixed payments on its assets and the fixed costs of Young 2 generation.[35] Square Butte is also required to continue to make its books and records available to Minnesota Power on a transparent basis. That provision allows Minnesota Power to reconcile all charges and invoices received from Square Butte.[36] Minnkota has agreed to forego allowing Square Butte to issue any additional or new debt that unfairly allocates costs. Any make whole payment by Square Butte will be allocated between Minnkota and Minnesota Power based on their respective MW capacity share of the Young 2 production.[37]

34. Pending all state and federal regulatory approvals, Minnesota Power represents that the proposed closing for the transactions will be December 31, 2009.[38]

35. As Young 2 energy deliveries phase out, Minnesota Power plans to add significant wind-based energy supplies in central North Dakota.[39] That additional wind energy would be delivered via the freed-up transmission capacity of the DC Line and would help the Company meet Minnesota’s Renewable Energy Standard (“RES”).[40]

36. In addition to using the DC Line to transmit its current Young 2 energy supply, Minnesota Power is also using that line to transmit wind energy from Oliver County I & II Wind Energy Center.[41] Additionally, Minnesota Power is developing wind project with an initial capacity of 75.9MW (“Bison I Project”) near Center, North Dakota for which it has existing transmission rights on the DC Line. The Company plans to begin commercial operation of that facility by late-2010.[42] A separate cost recovery eligibility filing for the 75.9 MW project was approved by the Commission in an order dated July 7, 2009.[43]

II. APPLICABLE LAW

37. Review of the DC Line purchase is governed by Minn. Stat. § 216B.50, subd. 1, which provides, in part, that:

No public utility shall sell, acquire, lease, or rent any plant as an operating unit or system in this state for a total consideration in excess of $100,000 … without first being authorized so to do by the commission. … If the commission finds that the proposed action is consistent with the public interest, it shall give its consent and approval by order in writing. In reaching its determination, the commission shall take into consideration the reasonable value of the property, plant, or securities to be acquired or disposed of, or merged and consolidated.

In determining whether a transaction is in the public interest, no single factor is determinative; the overall benefits of the sale should exceed the overall detriments. The public utility seeking approval of the transaction bears the burden of proof.[44]

38. Since the proposed Transactions will affect Minnesota Power’s resource needs, particularly its needs for renewable energy and the way in which the Company will meet those needs, it is necessary to analyze the proposed Transactions under Minn. R. 7843.0400, and Minn. R. 7843.0500. Minn. R. 7843.0400, subp. 4, provides:

A utility shall include in its resource plan filing a nontechnical summary, not exceeding 25 pages in length and describing the utility's resource needs, the resource plan created by the utility to meet those needs, the process and analytical techniques used to create the plan, activities required over the next five years to implement the plan, and the likely effect of plan implementation on electric rates and bills.

39. More specifically, the proposed Transactions will create “changed circumstances” within the meaning of Minn. R. 7843.0500, subp. 5, which provides:

The utility shall inform the Commission and other parties to the last resource plan proceeding of changed circumstances that may significantly influence the selection of resource plans. Upon receiving notice of changed circumstances, the Commission shall consider whether additional administrative proceedings are necessary before the utility’s next regularly scheduled resource plan proceeding.

40. Minn. R. 7843.0500, subp. 3, governs the scope of Commission review of utility resource plans and provides:

In issuing its findings of fact and conclusions, the commission shall consider the characteristics of the available resource options and of the proposed plan as a whole. Resource options and resource plans must be evaluated on their ability to:

A. maintain or improve the adequacy and reliability of utility service;

B. keep the customers' bills and the utility's rates as low as practicable, given regulatory and other constraints;

C. minimize adverse socioeconomic effects and adverse effects upon the environment;

D. enhance the utility's ability to respond to changes in the financial, social, and technological factors affecting its operations; and

E. limit the risk of adverse effects on the utility and its customers from financial, social, and technological factors that the utility cannot control.

41. When transactions similar to the proposed Transactions involve a transfer to a utility under Federal Energy Regulatory Commission (FERC) jurisdiction, the evaluation of the public interest of the transactions is guided by five specific criteria in Minn. Stat. § 216B.16, subd. 7c (a). Although the proposed Transactions do not transfer assets covered by that statute, some of the public interest criteria set out in that statute also represent reasonable criteria for assessing the public interest in the Transactions. Minn. Stat. § 216B.16, subd. 7c (a) provides, in pertinent part:

In assessing the public interest, the commission shall evaluate, among other things, whether the transfer:

(1) facilitates the development of transmission infrastructure necessary to ensure reliability, encourages the development of renewable resources, and accommodates energy transfers within and between states;

* * *

(4) impacts Minnesota retail rates;

* * *

III. PUBLIC INTEREST ANALYSIS

A. Overall Public Interest

42. In its May 4, 2009 Petition, Minnesota Power lists four main benefits to the transactions: (1) avoiding the cost and environmental effects of building a new line, since the DC Line already exists; (2) securing access to high quality renewable resources; (3) providing strategic energy benefits through reducing Minnesota Power’s carbon intensity, expanding Minnesota Power’s renewable resources, and diversifying Minnesota Power’s energy supply; and (4) maintaining an adequate and competitive power supply.[45]

43. The MCEA recognized these benefits when it supported approval of the Transactions as being in the public interest, stating:

Minnesota enacted important policies in 2007 that the Minnesota Power proposal advances. For example, Minnesota’s renewable energy standard, Minn. Stat. § 216B;1691, expects electric utilities like Minnesota Power to increase their sales of renewable energy to their customers, so that renewable energy is at least 25% of the utilities’ generation portfolio by 2025. Because electric utilities in Minnesota are too dependent on generation sources like coal that emit harmful pollutants, including greenhouse gases, the need to achieve the renewable energy standard is critical. Minnesota Power’s proposal and ability to satisfy the renewable energy standard by accessing some of the best wind resources located in North Dakota is firmly in the public interest.

In addition, the 2007 legislature enacted greenhouse gas reduction goals. Minnesota Power’s proposal in this docket assists the utility in doing its part to reduce its reliance on greenhouse gas-emitting generation resources. Minn.. Stat. §216H 03 establishes a 15% greenhouse gas reduction goal for 2015, building to an 80% reduction by 2050. Because of the scientific consensus that these levels of greenhouse gas reductions are necessary to avert the most catastrophic effects of climate change, it is imperative that Minnesota utilities take the goals set forth in Minnesota law seriously, and take swift action. Minnesota Power’s proposal to divest its interest in Milton R Young-Unit 2 is an important first step in reducing the utility’s contribution to greenhouse gas emissions.

Finally, federal legislative or regulatory action to mandate greenhouse gas reductions is extremely likely in the near term. For such mandates to be effective in reducing the nation’s greenhouse emissions at the levels scientific consensus says is necessary, federal action will have to significantly alter the economics for emitting greenhouse gases, and create incentives for cleaner alternatives. It is therefore prudent for Minnesota Power to take action now to reduce the financial risk its customers will face in a regulatory environment that puts a price penalty on greenhouse gas emissions.[46]

B. Development of Necessary Transmission Infrastructure

44. The Commission specifically requested the ALJ and the parties to address whether the volume of renewable energy supplies potentially movable over the direct-current line would be proportional to the need for renewable energy.[47] That question is closely related to the inquiries in Minn. R. 7843.0500, subps. 3A, C, and D relating to the adequacy and reliability of the Company’s service, minimizing adverse effects upon the environment, and the Company’s ability to respond to changes affecting its operations, such as statutory renewable energy requirement. The Commission’s question is also closely related to the first public interest factor set forth in Minn. Stat. § 216B.16, subd. 7c(a)(1), that requires an inquiry into whether the Transactions facilitate the development of transmission infrastructure necessary for reliability and the development of renewable resources.

45. In 2007, the Minnesota Legislature passed the renewable energy standard (“RES”), Minn. Stat. § 216B.1691, which requires electric utilities to meet renewable energy requirements of increasing percentages from 2012 through 2025.[48] In 2025, twenty-five percent of Minnesota Power’s energy supply must be derived from renewable energy.[49]

46. The Transactions create a path for wind resources to be developed in North Dakota for meeting Minnesota Power’s current and future needs for renewable resources. Approval of the Transactions will also facilitate the construction of an additional 345 kV line by Minnkota to provide power to its own customers. The results of these developments will more diverse and reliable energy resources.

47. Minnesota Power’s current estimates for the use of the DC Line are as follows: First, Minnesota Power indicates that the Oliver 1 (50.6 21 MW), Oliver 2 (48 MW), and Bison 1 (75 MW) projects are scheduled to use the DC Line by 2012. Second, Minnesota Power plans to add an additional 300 MW of wind capacity over the planning horizon. Thus, Minnesota Power’s current plans include 473.6 MW of wind capacity.[50] Although Minnesota Power will use the DC Line to take its declining share of Young 2’s output by 2026 the Company expects to have construction of its entire portfolio of wind completed. Thereafter, the Company will no longer be taking any output from Young 2.[51] Minnesota Power indicates that approximately 77 MW (550 MW minus 473 MW) of transmission capability will be “surplus” by 2026. [52]

48. To meet its RES requirements for the year 2025, Minnesota Power estimates its overall renewable energy requirement to be in the range of 2.4 million to 3.6 million MWh on an annual basis.[53] The OES estimates that by 2025 Minnesota Power will require 1.0 million MWh to 2.2 million MWh in addition to the energy from existing renewable sources and projects currently being implemented.[54] Existing renewable sources and projects currently being implemented include the Oliver 1 (50.6 MW), Oliver 2 (48 MW), and Bison 1 (75 MW) projects (Total of 173.6 MW).[55] Assuming a 45 percent capacity factor for North Dakota wind, the planned addition of 300 MW of incremental wind would produce about 1.18 million MWh annually. Thus, the current planned amount of 473.6 MW of wind capacity, a further 300 MW, and the anticipated surplus of 77 MW of incremental wind energy, taken together, would produce about 1.49 million MWh annually.[56] The ALJ concludes that that amount of wind energy would allow Minnesota Power to meet all, or at least a majority of, the renewable energy that the Company is likely to require by 2025.

49. The OES evaluated the amount of renewable energy potentially movable over the DC Line compared to the need for renewable resources. The volume of additional renewable energy supplies potentially movable over the DC Line covers the low end of the Company’s renewable energy requirement estimate, and the volume is significantly less than the high end of the renewable energy requirement estimate.[57] The OES therefore concluded that capabilities of the DC Line reasonably match Minnesota Power’s need for renewable resources.[58]

50. In view of the above findings, the ALJ concludes that the volume or renewable energy supplies potentially movable over the DC Line is proportional to Minnesota Power’s need for renewable resources.

51. The ALJ also concludes that because the Transactions will combine to create a path for wind resources to be developed by the Company in North Dakota, the transactions will maintain or improve the adequacy and reliability of Minnesota Power’s service, minimize adverse effect upon the environment, and enhance the Company’s ability to respond to changes affecting operations, specifically meeting Minnesota Power’s current and future needs for renewable resources. The Transactions will therefore satisfy the criteria set forth in Minn. R. 7843.0500, subps. 3A, C, and D.

52. The ALJ further concludes that the Transactions will facilitate the development of transmission infrastructure necessary for reliability and the development of renewable resources and will therefore satisfy the public interest criterion set forth in Minn. Stat. § 216B.16, subd. 7c(a)(1), to the extent that that criterion helps define the public interest in this proceeding.

C. The Transactions Represent the Least-Cost Method for Minnesota Power to Meet Its Renewable Energy Obligations

53. The Commission also specifically requested the ALJ and the parties to address whether the proposed Transactions are the least-cost method for the Company of meeting its renewable energy obligations.[59] That question is closely related to the inquiries in Minn. R. 7843.0500, subps. 3B, C and D relating to keeping customers’ bills and the Company’s rates as low as practicable, minimizing adverse effects upon the environment, and enabling the Company’s to respond to changes affecting its operations, such as statutory renewable energy requirements. The Commission’s question is also closely related to the first public interest factor set forth in Minn. Stat. § 216B.16, subd. 7c(a)(4), that requires an inquiry into how the Transactions are likely to impact Minnesota retail rates.

54. Minnesota Power analyzed three impacts that the Transactions would have on the Company’s obligations under the RES. The Company first analyzed the benefit or other impacts the Transactions would have on the cost to the Company of meeting the Minnesota renewable mandates Second, it analyzed the impact that the Transactions would have on carbon emissions for the Minnesota Power footprint. and third, Third, the Company analyzed the power cost for the reduced coal-fired resource from North Dakota — i.e.,Young 2 generation.[60]

55. Having identified the three areas of analysis, the Company developed three different scenarios — a Base (or Expected), High and Low scenario — to capture the uncertainty surrounding future replacement power and renewable energy costs, along with potential carbon futures, as well as the potential range of impact that this project would bring to the Minnesota Power customers. The Base scenario was based on assumptions associated with an ‘expected’ future for future power costs, carbon futures and renewable mandate implications (expected savings/benefits). The High scenario was based on an optimistic outlook (high savings/benefits) for these key variables affecting the decision, and the Low scenario was a pessimistic outlook (low savings/benefits). It was the Company’s belief that development of those three scenarios would provide a reasonable basis for strategic decision making.[61]

56. The company assessed the carbon impact of the North Dakota project by identifying the change in carbon emissions caused by implementing the project and then applied a value for emissions of CO2. As this project removes Young 2 generation from the Minnesota Power system and new wind generation is added, there would be an overall reduction in carbon emissions for Minnesota Power over the study period. The reductions in carbon emissions helped quantify the overall carbon benefit that would be brought to Minnesota Power customers. More specifically, the analysis assumed that for each metric ton of carbon reduced by the project, there would be an applied savings or avoided cost for customers equal to the value of the estimated carbon tax per metric ton over the study period. After calculating the carbon reduction on an annual basis, the analysis applied three levels of carbon tax futures to the Expected, High, and Low savings scenarios. After considering available forecasts, Minnesota Power selected a levelized $30/metric ton carbon tax for the expected case scenario, with low and high scenarios assigned a levelized $9/metric ton and $50/metric ton carbon tax, respectively.[62]

57. For the replacement power impact of this project, Minnesota Power evaluated the costs associated with reducing Young 2 energy and capacity from its resource mix gradually from 2013 through 2026. To determine the replacement energy cost component, Minnesota Power ran a production cost generation dispatch scenario for its system with and without Young 2 generation for the planning period to determine what resources would be needed to replace the reduced energy from the Young 2 resource. The difference between the two cases includes a component of wholesale market purchases and a ramping up of the existing Minnesota Power generation fleet resources to meet the loss of Young 2 energy. To quantify the cost component of the replacement energy, the production dispatch model for the Expected scenario included natural gas prices starting at $8.00/MMBtu, associated wholesale market prices, and the existing fleet dispatch costs. The two components (market energy costs and existing fleet energy dispatch costs) were aggregated together based on the amount of each included in the replacement dispatch to identify an annual replacement energy price to associate with the energy lost from the Young 2 resource. For the High and Low scenarios a natural gas price of $6.00/MMBtu and $10.00/MMBtu were used respectively (as replacement power is a cost, the higher priced energy was associated with the low savings scenario). For all three scenarios, the capacity that phased out with the Young 2 generation from 2013 – 2026 was replaced with peaking capacity. The replacement energy costs and capacity savings were netted together on an annual basis to determine an overall replacement power cost for the North Dakota Wind Project.[63]

58. Based on its analyses, Minnesota Power concluded that completing the North Dakota Wind Project could be expected to bring a range of potential benefits to Minnesota Power ratepayers of $13 Million to $275 Million reflecting the potential Low and High scenarios for the project and an Expected net benefit of $146 Million of net benefit over the study period.[64]

59. OES Witness Rakow and LPI Witness Hayet reviewed and tested the Company’s analyses. Both witnesses used somewhat different methodologies, calculations, and assumptions, but both reached essentially the same conclusion.[65] Minnesota Power agreed with the overall conclusion of both witnesses.[66]

60. OES Witness Rakow summarized his conclusions as follows:

The result of my calculations, assuming the low end of the range for carbon savings, renewable energy savings, and externality costs, is that the proposed Transactions represent a benefit of about $63.2 million PV. The result, assuming the high end, is a benefit of $293.9 million PV. Therefore, I conclude that the proposed Transactions are the least cost method for the Company to fulfill its obligations under the renewable energy standard.[67]

61. LPI Witness Hayet summarized his conclusions as follows:

Based on a review of the Company’s Base Case and sensitivity analyses, I believe the Company’s results are reasonable, and that the Company should be authorized to proceed with the proposed transactions. Although I do have some minor concerns about the Company’s analyses, I don’t believe that those concerns are of sufficient magnitude that addressing them would alter the outcome of the Company’s analysis.[68]

62. In view of the above findings, the ALJ concludes that the Transactions that Minnesota Power proposed are the least-cost method for the Company to meet its obligations under the RES.

63. The ALJ also concludes that the Transactions will combine to keep customers’ bills and the Company’s rates as low as practicable, minimize adverse effects upon the environment, and enhance the Company’s ability to respond to changes affecting operation, specifically meeting Minnesota Power’s current and future needs for renewable resources. The Transactions will therefore satisfy the criteria set forth in Minn. R. 7843.0500, subps. 3B, C and D.

64. The ALJ further concludes that the Transactions will reduce the impacts that the RES will have on Minnesota Power’s retail rates and will therefore satisfy the public interest criterion set forth in Minn. Stat. § 216B.16, subd. 7c(a)(4), to the extent that that criterion helps define the public interest in this proceeding.

D. The Capacity of the DC Line Not Used for Transmission of Renewable Energy Will Be Insignificant

65. The Commission directed the parties and the ALJ to evaluate whether the capacity of the DC Line will significantly exceed the capacity required to meet the RES and, if so, how the line's "excess capacity" should be treated,[69] Based on information provided by the Company, OES Witness Rakow determined the capacity of the DC Line will be 550 MW and that Minnesota Power’s current plans include 473.6 MW of wind capacity.[70] In addition, the DC Line will be used to transmit Minnesota Power’s declining share of the output from Young 2 until 2026.[71] The excess of transmission capacity over Minnesota Power’s planned use is 77 MW.[72] However, as noted by OES Witness Rakow, Minnesota Power may need additional renewable resources. Minnesota Power agreed with this conclusion.[73]

66. In view of the above, the ALJ concludes that the capacity of the DC Line will not significantly exceed the capacity required by Minnesota Power to meet its RES requirements. Any available excess capacity not used by Minnesota Power will be subject to the FERC open access requirements,[74] and the FERC process will address how any excess capacity would be used. [75]

E. Summary of Public Interest Analysis

67. The proposed Transactions satisfy the pertinent public interest criteria in Minn. Stat. § 216B.16, subd. 7c (a)(4) and Minn. R. 7843.0050, subp. 3, to the extent that those criteria assist in determining whether the proposed Transactions are consistent with the public interest within the meaning of Minn. Stat. § 216B.50, subd. 1.

68. The proposed Transactions will also result in a volume of renewable energy supplies potentially movable the DC Line proportional to Minnesota Power’s need for renewable resources and are the least-cost method for the Company to meet its obligations under the RES. Moreover, the excess capacity of the DC Line will not significantly exceed the capacity required to meet the RES.

69. The economic analyses that the parties conducted compared implementing the proposed Transactions to continuing with Minnesota Power’s prior RES compliance plan and concluded that this project’s potential benefits significantly exceeded its potential costs.[76] Translated into rate impact, implementing the proposed Transactions will cause rates to be lower than they would otherwise have been under Minnesota Power’s prior RES compliance plan.[77]

70. Since Minnesota Power’s petition is not proposing a new facility, the analysis in this Docket is analogous to Certificate of Need and siting proceedings. Detailed information regarding rate impacts is not available. That information will not be available until Minnesota Power's next rate case. The information that is available is the annual cost impact of the proposed project.[78]

71. The Transactions proposed by Minnesota Power are the least-cost method of meeting its obligations under the Renewable Energy Standard. As such, the Transactions meet public interest criteria relating to rates. The impact on Minnesota retail rates favors Commission approval of Minnesota Power’s application.

72. In determining whether the proposed Transactions are reasonable and prudent, it was the understanding of OES Witness Rakow that:

This criterion refers to the net effect of the proposed Transactions. Considering the results of the cost analysis, as long as Dr. Amit’s concerns are addressed, I conclude that the proposed Transactions are reasonable and prudent.[79]

73. It is the position of the OES that its analysis supports a finding that the Transactions are in the public interest, subject to certain conditions that OES has proposed.[80]

F. Summary of Resource Planning Analysis

74. As part of its public interest analysis, the OES analyzed the Transactions under the framework of resource planning as set out in Minn. Rule 7843.0500. Under that framework, the OES concluded that:

The proposed Transactions have either no impact or a positive impact on the resource planning criteria. There may be a positive impact to the extent that the Transactions increase MP’s renewable resources without adding significant new infrastructure.[81]

75. The proposed Transactions satisfy the evaluative criteria set forth in Minn. R. 7843.0050, subp. 3.

IV. CONTESTED CONDITIONS

A. Potential Capacity and Energy Payments to Minnkota

76. It is the opinion of OES witness Dr. Amit that provisions of the New Minnesota Power PPA, taken together, are contrary to the public interest because they would result in Minnesota Power being obligated to pay Minnkota for contracted, but undelivered, capacity and energy for up to twelve consecutive months.[82]

77. The concerns identified by Dr. Amit relate to the terms in the restructured PPAs. On May 29, 1998, Minnesota Power entered into a power purchase agreement to purchase power from Square Butte (Minnesota Power PSA). On April 30, 2009, Minnesota Power, Minnkota, and Square Butte executed an Amended and Restated Master Generation Planning Agreement (Master Agreement). Among other things, the Master Agreement contained two proposed new Purchased Power Agreements. The first covered power purchased by Minnkota from MP (New Minnkota PPA), and the second covered power purchased by MP from Minnkota (New Minnesota Power PPA). Neither new PPA is to become effective until the closing date of the transactions being submitted for Commission approval.[83]

78. Section 3.6 of the New Minnkota PPA contained the following provision for an Exchange Option:

Exchange Option. Minnesota Power grants Minnkota the exclusive option (the “Exchange Option”) to be effective as of the Exchange Option Exercise Date, to surrender and terminate the New Minnkota PSA and exchange the Minnesota Power PSA for the Revised Minnesota Power PPA (the “Exchange”). If Minnkota exercises the Exchange Option, Minnkota will surrender the New Minnkota PSA in exchange for the Revised Minnesota Power PPA. Minnkota shall request Square Butte to consent to such Exchange in order to exercise the Exchange Option.[84]

79. In other words, in the event that Minnkota does exercise its Exchange Option, the proposed New Minnesota Power PPA replaces the existing PPA that Minnesota Power has with Square Butte. Under the replacement PPA, Minnesota Power becomes entitled to certain receive scheduled net capability and capacity entitlements.[85]

80. Those scheduled net capability and capacity entitlements are covered in Article III, Section 3.2, of the New Minnesota Power PPA , which states in pertinent part:

[U]nder this Agreement beginning on the Exchange Option Exercise Date and during the time period indicated below, Minnesota Power shall purchase from Minnkota and be entitled to the percentage entitlement of Net Capability, and to the Energy associated with such entitlement to Net Capability as measured at the Delivery Point for Energy for the remaining time period in which the Exchange Option Exercise Date occurs, and for the corresponding percentage entitlements of Net Capability and associated Energy for the subsequent time periods as follows.[86]

A table in that Section establishes a schedule of percentage entitlements of Net Capacity that begins at 50% on the Closing Date and progressively decline to 0% on January 1, 2026.

81. Section 4.1 of the Proposed PPA provides, in part:

Monthly Charges. Minnesota Power shall pay to Minnkota for each Month of each Contract Year a monthly charge (hereinafter called the “Monthly Charge for Capacity and Energy”), regardless of the percentage entitlement of Net Capability or Alternate Capacity actually made available to Minnesota Power or the amount of Energy or Alternate Energy actually delivered to Minnesota Power, except as provided in Section 4.4.[87]

82. Sections 4.1.1 et seq., describe how the Monthly Charges for Capacity and Energy are to be calculated.

83. Section 4.5.1 of the Proposed PPA provides:

Obligation to Make Payment. Except as provided in Section 4.5.2, Minnesota Power shall make all payments that are required pursuant to the terms of this Agreement at such time or times herein provided for such payments, notwithstanding (1) the non-performance of Minnkota of any of its obligations herein or in the Joint Operating Agreement, whether due to Uncontrollable Forces or otherwise; (ii) the failure, inoperativeness or suspension, interruption or interference of the operation of Unit #2; (iii) the failure to make available to Minnesota Power its percentage entitlement of Net Capacity or Alternate Capacity or to deliver to Minnesota Power the Energy or Alternative Energy (except provided in Section 4.5.2; (iv) the invalidity or unenforceability or lack of due authorization of this Agreement; or (v) any other matter or event whatsoever, including without limitation the bankruptcy or insolvency of Minnkota or the disaffirmance of any agreement by any trustee or receiver, which might otherwise relieve Minnesota Power from the obligation to pay such amounts at such times, notwithstanding any present or future law to the contrary.[88]

84. Section 4.5.2 of the Proposed PPA provides:

Suspension of Payment Obligation. Minnesota Power’s obligation to pay charges under Section 4.1 shall be suspended only in the event that Minnkota does not receive from Square Butte and Minnkota fails to deliver any Energy or Alternate Energy whatsoever to any Delivery Point for a period of twelve (12) consecutive Months. Such suspension, if any, shall begin at 12:01 a.m. CPT of the first (1st) day of the Month following such twelve (12) Month period, and shall continue until such time as Minnkota shall resume the delivery to Minnesota Power of any Energy or any Alternate Energy at any Delivery Point; provided, however, that such suspension shall not relieve Minnesota Power of its obligation to make payment of the Monthly Charges for Capacity and Energy incurred prior to the commencement of such suspension.[89]

85. Based on the testimony of its witness Dr. Amit, the OES maintains that Sections 4.1, 4.5.1, and 4.5.2 of the New Minnesota Power PPA, taken together, are contrary to the public interest because they would result in Minnesota Power being obligated to pay Minnkota for contracted, but undelivered, capacity and energy for up to twelve consecutive months. This, OES argues, would inappropriately shift the financial risk of nonperformance and failure to provide the contracted capacity and energy for events other than force majeure events to MP’s ratepayers, rather than that risk being borne by Minnkota or by MP’s shareholders.[90]

86. The OES suggests two alternative approaches to correcting what it considers to be an inappropriate allocation of financial risk. One alternative is to amend the New Minnesota Power PPA to require the Company to pay Minnkota only for capacity and energy actually delivered. The second alternative is to approve the New Minnesota Power PPA without changes but allow the Company to recover from ratepayers only the costs of capacity and energy actually delivered by Minnkota to Minnesota Power.[91] In effect, the second alternative shifts the risk of Minnkota’s failure to provide the contracted capacity and energy to Minnesota Power’s shareholders.

87. The OES favors the second alternative and recommends that the Commission approve MP’s Petition subject to the following conditions:

(1) MP may only recover the cost of capacity payments for capacity actually credited to MP; and

(2) MP may recover the cost of alternate energy only up to the level of the cost of the energy that would have been provided by Young 2.[92]

88. Minnesota Power disagrees with the OES position that the proposed contractual obligation to pay Minnkota for contracted, but undelivered, capacity and energy is contrary to the public interest. Minnesota Power addressed the OES’s objections and recommendation by citing five reasons why the terms of the New Minnesota Power PPA should not be altered or conditions imposed on Commission approval of its Petition.[93]

89. First, Minnesota Power argues that the current Minnesota Power PSA between the Company and Square Butte, which was executed on May 29, 1998, contains identical provisions, and that those provisions have never been invoked or resulted in a cost to ratepayers during the last eleven years.[94] In response, the OES argues that neither past practice nor the absence of past triggering events makes inappropriate provisions appropriate.[95]

90. Second, the Company argues New Minnesota Power PPA, which contains the contract provisions in question, will only become effective if and when Minnkota actually exercises the Exchange Option. Moreover, that is likely to happen only if Square Butte has a significant financing need. If such a need is met, for example, by issuing bonds, then payments for undelivered capacity and energy will be needed to pay bond obligations if a major outage were to occur. Minnesota Power further argues that the existence of these undelivered capacity and energy obligations will reduce investment risk and therefore the financing cost for Square Butte. Lower financing costs will, in turn, reduce the cost of the power that MP ratepayers pay for power purchased from Square Butte.[96] In response, the OES argues that it is not clear that the existence of undelivered capacity and energy obligations will necessarily result in least-cost financing for Square Butte. Moreover, those payment obligations constitute imputed long term debt which results in higher debt and equity costs for Minnesota Power. On balance, the existence of those obligations may therefore result in a net increase, rather than net decrease, in the cost of power that the Company purchases from Square Butte.[97]

91. Third, Minnesota Power does not have an ownership interest in Young 2, and it is therefore not a rate-based asset. Nevertheless, the Company argues that Young 2 is analogous to a rate-based asset because, unlike an independent power producer, Square Butte does not build a risk premium or a rate of return component into the purchase price that Minnesota Power pays. Thus, the Company contends, its ratepayers pay decreased costs for power supplied by Young 2. The Company further argues that those decreased costs are possible because Minnesota Power and Minnkota provide the only credit support for Square Butte’s debt financing through the obligations they have contracted for in their respective PPAs. MP contends that those obligations, including the obligation to pay for contracted but undelivered capacity and energy, are therefore what make the reduced power costs to ratepayers possible.[98] In response, the OES argues that if Minnkota exercises the exchange option and the Revised Minnesota Power PPA and the obligations at issue become effective, then Minnesota Power ratepayers will be holding Minnkota financially harmless from the risk of its nonperformance due to a major Square Butte outage. The OES contends that this is then more properly a risk that Minnkota ratepayers or shareholders should bear, as opposed to the ratepayers or shareholders of Minnesota Power, regardless of how both companies decide to finance Square Butte.[99]

92. Fourth, the Company contends that if Young 2 were to experience an extended forced outage of less than 12 months, Minnesota Power could still count the capacity under MISO accreditation rules as long as Young 2 were placed back in service within that time frame.[100] The OES agreed that in that event, Minnesota Power should continue making its capacity payments. However, in essence the OES argues that Minnesota Power should not also be obliged to pay fixed costs for energy that is not delivered when the Company would be required to purchase energy from other sources to meet its peak load capacity.[101]

93. Fifth, the Company points out that under Article III, Section 3.2, of the New Minnesota Power PPA, the Company’s percentage entitlements of Net Capacity will begin at 50% on the Closing Date and progressively decline to 0% on January 1, 2026. The company therefore argues that any ratepayer financial risk associated with paying Minnkota for capacity and energy not actually delivered will correspondingly decline and will no longer represent any risk on January 1, 2026.[102] The OES responded that although the risk to the Company’s shareholders would decline over time and eventually disappear in 2026, it still would be a risk more properly borne by the Company’s shareholders than its ratepayers.[103]

94. In the final analysis, the ALJ concludes that approval of the transmission line purchase and associated agreement will be in the best interests of Minnesota Power’s ratepayers, shareholders, and the public at large. Since requiring the Company to amend the New Minnesota Power PPA to require the Company to pay Minnkota only for capacity and energy actually delivered might jeopardize consummation of the pending transaction, the ALJ concludes that such a condition of approval would not be in the public interest.

95. Furthermore, since it appears to be commercially reasonable for Minnesota Power to recover from its ratepayers the cost of capacity and the cost of producing energy that is actually delivered to the Company by Minnkota, the ALJ recommends that the Commission place no conditions on approval that would prevent that from occurring in the event that Minnkota exercises the Exchange Option.

96. However, the ALJ concludes that it would not be commercially reasonable and in the public interest for MP to recover from its ratepayers the cost of energy not actually delivered to the Company by Minnkota in the event that it exercises the Exchange Option. First, Minnesota Power’s arguments that the risk of nondelivery for up to twelve consecutive months is essentially de minimis because of past practice and experience, relative unlikelihood that the Exchange Option will be exercised, and the declining nature of the risk over an eight-year period apply with equal force to risk that is borne by ratepayers or by shareholders. Second, allowing the Company to recover from ratepayers both capacity costs and the costs of producing energy that is actually delivered further diminishes the potential financial risk to shareholders.

97. There appears to be no compelling commercial reason for Minnesota Power ratepayers to bear the financial risk of having to pay for the costs of undelivered energy under the New Minnesota Power PPA, and there is no apparent commercial reason or public policy consideration for relieving MP shareholders of that risk. For these reasons, the ALJ concludes that it would be in the public interest for the Commission to condition approval of the Transactions on the terms set out in Finding 87, above.

B. Limiting the Cost of Curing Future Easement Defects

98. In Article VII of the Asset Purchase Agreement, Minnesota Power assumes responsibility to cure easement defects discovered prior to closing.[104] The LPI expressed concern that ratepayers could be responsible for litigation and other costs associated with curing easement defects discovered after the Transactions closed. Specifically, the LPI contemplate such problems as tax forfeitures, railroad and highway crossings, recording problems that might not be discoverable before closing. The LPI propose that Minnesota Power avoid having any responsibility for easement defects through a title insurance policy. They also recommend that the Commission cap recovery for any expenses related to curing easements that Minnesota Power subsequently incurs at $25,000.[105]

99. Minnesota Power acknowledged the possibility of undiscovered easement defects but argued that the cost of curing future easement problems cannot be quantified. Moreover, the Company further characterized the possibility of significant financial impact from undiscovered easements as “a remote possibility that can be addressed at the time, if necessary.”[106]

100. Minnesota Power has had considerable experience with the kinds of property transactions involved in the transfer of DC Line assets. Moreover, the kinds of easement problems to which the LPI refer are no different than the kinds of easement problems that periodically arise with any electrical utility’s existing transmission lines. There is no evidence that such problems have previously resulted in significant costs to the Company’s ratepayers. The ALJ therefore concludes that the terms of the Transactions regarding responsibility for easements are reasonable and prudent and concludes that Commission approval of the Transactions should not be conditioned on requiring Minnesota Power to obtain a title insurance policy or on capping recovery for any easement-curing related expense assumed by Minnesota Power at $25,000.

C. Requiring an RFP Process for Future North Dakota Wind Generation Projects

101. LPI Witness Hayet’s expressed skepticism that future North Dakota wind generation projects constructed by Minnesota Power would necessarily be the lowest cost option for the Company, as opposed, for example, to purchasing wind energy from some third party vendor. He testified that:

[T]he Commission should not explicitly or implicitly agree that the Company itself should construct the additional wind resources in North Dakota. When the time comes to acquire the additional North Dakota wind resources, the Company should be required to conduct an RFP to determine which additional wind resources should either be constructed or acquired. In other words, it is possible that other renewable resource suppliers could provide renewable energy to MP at lower cost than what MP could provide. The best approach would be to conduct an RFP in which MP could bid in its own projects, and the lowest cost project could be selected to provide the renewable energy.[107]

102. The LPI assert that Minnesota Power has not followed the Certificate of Need process, nor has it yet filed an amended IRP to demonstrate that the costs of constructing its own future wind generating project will be prudent. Based on that and Mr. Hayet’s testimony, the LPI contend that the Commission should require Minnesota Power to conduct an RFP process for any future North Dakota wind generation project to ensure that Minnesota Power pursues the most cost-effective alternative for obtaining future North Dakota wind energy that will be transmitted along the DC Line. The LPI argue that requiring such an RFP process is necessary to adequately protect Minnesota Power’s ratepayers.[108]

103. In response, Minnesota Power asserts that it will necessarily have the burden of proof to establish that any of its own future North Dakota wind projects will be the lowest cost and will involve the least expense for its customers. The Company further relies upon its experience with its Bison I wind application to demonstrate that its own new generation can be the lowest cost option for its customers.[109] In that docket, the Commission approved construction of the Company’s Bison I project based on cost comparisons that had been made by the OES.[110]

104. In view of the above findings, the ALJ concludes that the LPI have failed to establish that an RFP process is necessary to supplement the Commission’s existing processes for assessing new generation sources to assure that the Company will obtain the lowest cost North Dakota wind energy for future transmission on the DC Line.

D. Risk of Minnkota’s Failure to Complete Its Proposed 345kV Line

105. The LPI also ague that the possibility that Minnkota’s anticipated 345 kV line might not be completed poses an unreasonable risk to ratepayers because that would alter Minnesota Power’s scheduled use of the DC line, would require the Company to obtain more expensive alternative sources of renewable energy, and would diminish the projected monetary benefits that the Transactions would provide to ratepayers. The LPI propose that Minnesota Power recalculate the costs derived through its production cost planning model using actual data and compare the results with the forecast in this Petition. LPI further proposes that any difference between actual and projected costs would then be refunded to ratepayers.[111]

106. Alternatively, the LPI recommend modifying the terms of the Transactions to remove the provision that triggers the conclusion of 227.5 MW of firm point-to-point transmission service when the Minnkota 345 kV line comes into service. In its place, the LPI propose that Minnesota Power’s reassignment of 227.5 MW of firm point-to-point transmission service rights should run from the closing date until January 1, 2013. The LPI contend that that modification would ensure that “Minnesota Power can proceed as planned to meet the State renewable mandates and Minnkota is properly incentivized to timely conclude construction of the AC Line.”[112]

107. In response, Minnesota Power maintains that Minnkota has every financial incentive to permit and construct the 345 kV transmission line and is on course to do so by 2013.[113] Minnesota Power also contends that the failure to build the 345 kV line would leave ratepayers in the same position as if the Transactions had never occurred except for Minnesota Power now owning a significant transmission asset.[114]

108. Minnesota Power also objected to the LPI proposal as being unworkable from a contracting or implementation standpoint given the difficultly in assessing the potential direct rate impacts.[115] Minnesota Power stated that it was committed to keeping the Commission informed on the progress of the permitting and construction schedule of the new 345kV line through this Docket and through future Commission proceedings to assess Minnesota Power’s renewable resource plans under Minn. Stat. § 216B.1691, subd. 3, and Minnesota Power’s resource plans under Minn. Stat. § 216B.2422.[116]

109. In addition to the Company’s responses, the ALJ concludes that a fallacy underlies the LPI’s recommendation for the requested conditions. If the 345 kV line were not constructed, the result would not be an additional cost that the Company’s ratepayers would have to pay. Rather, that contingency would simply result in an unrealized benefit for ratepayers because the Company’s least-cost method of obtaining renewable energy would be some other proposal. In view of the above, the ALJ recommends that the Commission not impose conditions on approval of the Transactions requiring modifications to the Transactions or requiring Minnesota Power to make a refund to ratepayers in the event that Minnkota’s anticipated 345 kV line is not completed.

E. Termination of the Company’s Involvement on the Young 2 Operating Committee

110. The LPI also contends that terms in the Transactions specifying that Minnesota Power’s term on the Young 2 operating committee runs until Minnesota Power’s net entitlement to the output of Young 2 is 100 MW or less poses another risk to ratepayers. That is expected to occur in 2015.[117] The LPI’s concern is that, under the existing contractual terms, Minnesota Power will be ending its involvement in the process for deciding what Minnkota’s costs will be before the Company stops receiving energy from Young 2. The LPI suggest the Minnkota would have complete discretion to determine what costs it would be able from Minnesota Power under, for example, the Make Whole Adjustment. The LPI also express concern that any projects to address carbon emissions reduction for Young 2 will be planned and budgeted well after 2015, when Minnesota Power would no longer be a member of the operating committee. The LPI therefore propose that the Commission require changes to the Transactions to ensure that Minnesota Power will remain on the operating committee until the Company no longer entitled to power from that facility.[118]

111. In response, Minnesota Power asserts that its agreement to the provisions in the Transactions ending its involvement with the Young 2 operating committee before the Company stops receiving any energy from that facility was a matter of reasonable business judgment:

Certainly it was a judgment call on our part on when the time and effort needed to – to meaningfully participate in an operating committee was justified. And we participate now in that operating committee because we have 227 megawatts of the power, or half of the power out at the plant. We just made the judgment that when our take went down to a small enough level – in this case, when it gets to 100 megawatts -- that we wouldn't directly participate in the operating committee. Certainly our interests are very much aligned with Minnkota. Minnkota has every incentive in the world to keep the costs down on that project. And through the years our interests have been very much aligned. So, in our opinion, we didn't jeopardize our customers' costs at all by choosing to not directly participate.[119]

112. Minnesota Power has no ownership interest in Young 2.[120] The Company’s current participation in the operating committee arises from Minnesota Power’s entitlement to one-half of the electricity generated by that facility. One of the Transactions’ goals is ending Minnesota Power’s use of Young 2 as a source of energy. As Minnesota Power’s share of the output is reduced, the importance of Minnesota Power’s participating on the operating Committee is commensurately reduced. The ALJ therefore concludes that Minnesota Power’s agreement to terms in the Transactions that end the Company’s participation in the Young 2 operating committee before the Company stops receiving any energy from that facility was a matter of reasonable business judgment. The ALJ therefore concludes that the Commission should not impose a condition on its approval of the Transaction requiring modification of the Transactions to end Minnesota Power’s participation in the Young 2 operating committee only when the Company stops receiving energy from that facility.

V. UNCONTESTED CONDITIONS

113. Minnesota Power agreed to conditions regarding capacity premiums, transaction costs, and the timing of the reduction to Minnesota Power’s common equity ratio.[121] Those conditions are appropriate for adoption by the Commission. To the extent clarification is necessary regarding Minnesota Power’s “next” rate case, conditions referring to the next rate case should apply with reference to the first rate case filed by Minnesota Power subsequent to its rate increase in Commission Docket No. E-015/GR-08-415.

VI. OTHER FINDINGS

114. The citations to exhibits in the Findings are not intended to indicate that all evidentiary support in the record has been cited.

Based on these Findings of Fact, the Administrative Law Judge makes the following:

VII. OTHER CONCLUSIONS

1. The Minnesota Public Utilities Commission and Administrative Law Judge have jurisdiction to consider the Minnesota Power’s application for approval of the Transactions.[122]

2. No public utility shall sell any plant as an operating unit or system in Minnesota for total consideration in excess of $100,000 without being authorized to do so by the Commission.[123]

3. Although the Transactions do not involve a sale by Minnesota Power of ownership in a generating facility, the Transactions have a similar effect by modifying PPAs that vest Minnesota Power with the rights to the electricity generated. The Transactions are therefore subject to the Commission’s approval.

4. The Commission shall give its consent and approval by order in writing if the proposed sale is “consistent with the public interest.”[124] In assessing the public interest, the Commission shall evaluate several statutory criteria.[125]

5. The public utility seeking approval of a transaction bears the burden of proof that the statutory criteria are satisfied.[126]

6. Minnesota Power has demonstrated that

a. The Transactions facilitate the development of transmission infrastructure necessary to ensure reliability, encourage the development of renewable resources, and accommodate energy transfers within and between the states.

b. The proposed Transactions will maintain or improve the adequacy and reliability of Minnesota Power’s service and will keep its customers' bills and the Company’s rates as low as practicable, given regulatory and other constraints.

c. The proposed Transactions will minimize adverse socioeconomic effects and adverse effects upon the environment and will enhance the utility's ability to respond to changes in the financial, social, and technological factors affecting its operations.

d. Subject to the conditions described below, the proposed Transactions will limit the risk of adverse effects on the utility and its customers from financial, social, and technological factors that the utility cannot control.

e. Satisfy the evaluative criteria for reviewing resource plans contained in Minn. R. 7843.0050, subp. 3.

f. The Transactions will not have a negative impact on Minnesota retail rates.

g. The proposed Transactions will also result in a volume of renewable energy supplies potentially movable the DC Line proportional to Minnesota Power’s need for renewable resources and are the least-cost method for the Company to meet its obligations under the RES.

h. The capacity of the DC line will not significantly exceed the capacity required to meet the Company’s RES. Minnesota Power’s offering of any "excess capacity" pursuant to the FERC open tariff is reasonable.

i. The Transactions are reasonable and prudent, and in the public interest.

7. If the Commission approves the Transactions, it is in the public interest to condition approval upon Minnesota Power’s acceptance of certain limitations on costs that can be recovered from ratepayers, specifically:

a. MP may only recover the cost of capacity payments for capacity actually credited to MP; and

b. MP may recover the cost of alternate energy only up to the level of the cost of the energy that would have been provided by Young 2.

8. Any of the Findings more properly designated Conclusions are hereby adopted as such.

Based upon these Conclusions, the Administrative Law Judge makes the following:

RECOMMENDATION

The Administrative Law Judge respectfully RECOMMENDS that the Commission APPROVE Minnesota Power’s Petition to Purchase Square Butte Cooperative’s Transmission Assets and for Restructuring Power Purchase Agreements from Milton R. Young Unit 2 Generating Station., subject to the conditions set forth above.

Dated: October 27, 2009

s/Bruce H. Johnson

BRUCE H. JOHNSON

Administrative Law Judge

Reported: Shaddix & Assoc., 1 volume

NOTICE

Notice is hereby given that, pursuant to Minn. Stat. § 14.61, and the Rules of Practice of the Minnesota Public Utilities Commission and the Office of Administrative Hearings, exceptions to this Report, if any, by any party adversely affected must be filed by the date set by the Commission with the Executive Secretary, Minnesota Public Utilities Commission, 350 Metro Square, 121 - 7th Place East, St. Paul, Minnesota 55101, or electronically filed.

The Minnesota Public Utilities Commission will make the final determination of the matter after the expiration of the period for filing exceptions, or after oral argument, if it is held.

The Commission may accept or reject the Administrative Law Judge’s recommendation and this recommendation has no legal effect unless expressly adopted by the Commission as its final order.

[1] The proposed sale and associated agreements are hereafter referred collectively to as the “Transactions.”

[2] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 46; Paulseth Direct, Ex. 7 at 5.

[4] Hodnik Direct, Sched. I, Part 1, at 12; Minke Direct, Ex. 19 at 2.

[5] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 12; Rakow Direct, Ex. 16 at 2-3.

[6] The LPI are ArcelorMittal USA (Minorca Mine); Blandin Paper Company; Boise, Inc.; Enbridge Energy Limited Partnership; Hibbing Taconite Company; NewPage Corporation; Sappi Cloquet, LLC; United States Steel Corporation (Keewatin Taconite and Minntac Mine); and United Taconite, LLC.

[7] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 18-19.

[9] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 19.

[10] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 19; Tr. at 58.

[12] Hodnik Direct, Sched. I, Part 1, Ex. 3, n.13 at 19.

[17] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 18-19.

[19] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 46-48.

[20] Id. at 74-235; Hodnik Direct, Sched. I, Part 2, Ex. 4 at 236-313.

[21] Donahue Direct, Ex. 9 at 2; Hodnik Direct, Sched. I, Part 1, Ex. 3 at 83-121.

[22] Hodnik Direct, Sched. I, Part 3, Ex. 5 at 611; Minke Direct, Ex. 19 at 2.

[23] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 58; Rakow Direct, Ex. 16 at 4.

[25] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 49; Ex. 7 at 5.

[27] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 50, Hodnik Direct, Sched. I, Part 2, Ex. 4 at 436‑437; Paulseth Direct, Ex. 7 at 3.

[29] The Minnkota PSA would be executed at closing and is labeled Exhibit A-1 to the Master Generation Planning Agreement. Hodnik Direct, Sched. I, Part 1, Ex. 3 at 50-51; Paulseth Direct,Ex. 7 at 3; Hodnik Direct, Sched. I, Part 3, Ex. 5 at 492-533.

[30] Hodnik Direct, Sched. I, Part 2, Ex. 4 at 421; Tr. at 28.

[31] Hodnik Direct, Sched. I, Part 2, Ex. 4 at 433 (Table 3).

[32] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 40; Ex. 17 at 17-18; Tr. at 29.

[33] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 53; Ex. 5 at 510; Paulseth Direct, Ex. 7 at 7-8.

[34] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 53; Hodnik Direct, Sched. I, Part 3, Ex. 5 at 540‑572; Paulseth Direct, Ex. 7 at 8; Ex. 13. The New Minnesota Power PPA is labeled Exhibit A-2 to the Master Generation Planning Agreement.

[35] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 55; Paulseth Direct, Ex. 7 at 9; Hodnik Direct, Sched. I, Part 3, Ex. 5 at 440 (Public); Hodnik Direct, Sched. I, Ex. 2 at 440 (TS).

[36] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 55; Hodnik Direct, Sched. I, Part 3, Ex. 5 at 440.

[37] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 55; Paulseth Direct,Ex. 7 at 8-9; Hodnik Direct, Sched. I, Part 2, Ex. 4 at 429-430.

[38] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 24, 72.

[39] Id. at 31-33; Norberg Direct, Ex. 6 at 7-10; Tr. at 19-20.

[40] Hodnik Direct, Ex. 1 at 4-7; Paulseth Direct, Ex. 7 at 7-8; Rakow Direct, Ex. 16 at 8.

[41] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 20; Ex. 7 at 9-10; Rakow Direct, Ex. 16 at 6-7.

[42] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 20; Rakow Direct Ex. 16 at 6-7; Tr. at 31.

[44] See e.g. Minn. Stat. § 216B.16, subd. 4 (regarding changes in rates); Minn. R. 1400.7300, subd. 5; In re Northwestern Bell Tele. Co., 365 N.W.2d 341, 342 (Minn. App. 1985).

[45] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 23; Rakow Direct, Ex. 16 at 3-4.

[50] Those estimates were contained in Minnesota Power’s response to OES Information Request No. 10 and were relied upon by OES witness Rakow in his testimony. Rakow Direct, Ex. 16 at 6-7.

[56] Rakow Direct, Ex. 16 at 6-8; see also, Pierce Direct, Ex. 8 at 7-8.

[65] Rakow Direct, Ex. 16 at 9-17; Hayet Rebuttal, Ex. 17 at 7-14.

[83] Hodnik Direct, Sched. 1, Pt. 3, Ex. 5, at 493.

[85] Section 4.4 of the Master Agreement (Hodnik Direct, Sched. 1, Pt. 2, Ex. 5, at 432.

[86] Hodnik Direct, Sched. 1, Pt. 3, Ex. 5, at 541.

[88] Hodnik Direct, Sched. 1, Pt. 3, Ex. 5 at 558.

[90] OES Reply Brief, pp. 3-6; Amit Direct, Ex. 15, at 3-6.

[91] OES Reply Brief, p. 6; Amit Direct, Ex. 15 at 6.

[97] OES Reply Brief at p. 4; Ex. 15, Amit Direct, Ex. 15 at 8.

[99] OES Reply Brief at pp. 4-5; Amit Direct, Ex. 15 at 8-9.

[101] OES Reply Brief at p. 5; Amit Direct, Ex. 15 at p. 9.

[103] OES Reply Brief at pp. 5-6; Amit Direct, Ex. 15 at. 9-10.

[104] Hodnick Direct, Sched. 1, Ex. 3 at 101, Section 7.3(c).

[106] Minnesota Power Brief, at 12; Tr. at 48-49.

[109] Minnesota Power Brief, at 12; Tr. at 31.

[110] ITMO the Petition of Minnesota Power for Approval of Investments and Expenditures in the Bison I Wind Project for Recovery through Minnesota Power's Renewable Resources Rider Under Minn. Stat. Section 216B.1645, MPUC Docket E015/M-09-285, Order of July 7, 2009 at 6‑7.

[113] Tr. at 28; Hodnik Direct, Sched. 1, Part 2, Ex. 4 at 436 (Section 6.1 “Minnkota shall use its best efforts to permit, design, finance, procure, construct, install and complete the New AC Line.”); Donahue Direct, Ex. 9 at 8 and Sched. 1.

[114] Minnesota Power Brief, at 9-10; Tr. at 25-26, 35-38..

[115] Minnesota Power Brief, at 10; Tr. 93-94..

[116] Minnesota Power Brief, at 10; Tr. at 28; Ex. 4 at 436 (Section 6.2)...

[120] Hodnik Direct, Sched. I, Part 1, Ex. 3 at 18-19.

[121] LPI Reply Brief, at 1-2; Tr. at 29, 42.; Minnesota Power Brief, at 11.

[122] Minn. Stat. §§ 216B.16, subd. 7c, 216B.50 and 14.50.

[124] Minn. Stat. §§ 216B.50, subd. 1 and 216B.16, subd. 7c.

[126] See Minn. Stat. § 216B.16, subd. 4; Minn. R. 1400.7300, subd. 5; In re Northwestern Bell Tele. Co., 365 N.W.2d 341, 342 (Minn. App. 1985).