SEC Comment Letter 2015

414 Nicollet Mall

Minneapolis, MN 55401

Telephone (612) 330-5500

May 5, 2015

Ms. Jennifer Thompson

Accounting Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

Washington, D.C. 20549

Re: Xcel Energy, Inc.

Form 10-K for the Fiscal Year Ended December 31, 2014

Filed February 20, 2015

File No. 1-03034

Dear Ms. Thompson:

Reference is made to your letter to Ms. Teresa S. Madden, dated April 21, 2015, in which you transmitted comments of the Staff of the Division of Corporation Finance with respect to the above filing (the “Staff Comment Letter”). This letter is submitted on behalf of Xcel Energy Inc. (“Xcel Energy” or the “Company”) in response to the Staff Comment Letter. To assist you in your review, we have repeated the full text of the Staff’s comments in italics in this letter, and our responses follow immediately.

Form 10-K for the Fiscal Year Ended December 31, 2014

Notes to Consolidated Financial Statements

Revenue Recognition, page 92

1. We note that NSP-Minnesota and SPS participate in RTO’s in which they record revenues and charges related to serving retail and wholesale electric customers comprising the native load on a net basis within cost of sales. Alternatively, we note that you recognize revenues and charges for short term wholesale sales of excess energy transacted through RTO’s on a gross basis. Please tell us how you determined your presentation and classification of these items were appropriate.

Response:

The Company recognizes all sales to end use customers, native load and wholesale, on a gross basis.

In RTO markets, such as Midcontinent Independent System Operator, Inc. (MISO) and Southwest Power Pool, Inc. (SPP), Xcel Energy offers its generation and bids its native load into the market on an hourly basis. The RTO net settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout an RTO region. RTOs evaluate the market participants’ energy offers and demand bids to economically and reliably dispatch energy for an entire system.

Under the guidance of ASC 605-45 Revenue Recognition - Principal Agent Considerations (EITF 99-19) an RTO is deemed an agent and Xcel Energy is considered the primary obligor in respect to native load transactions. As the RTO is an agent facilitating sales to an end user, and is not changing or adding value to the product, the separate revenues and charges between the Company and the RTO should be recognized on a net basis. ASC 605-25-25-3 also sets forth guidance that separate contracts with the same entity or related parties that are entered into at or near the same time are presumed to have been negotiated as a package and shall, therefore, be evaluated as a single arrangement in considering whether there are one or more units of accounting. In addition, if offsetting purchase and sale transactions with the RTOs were recognized on a gross basis, sales of energy and associated costs would effectively double and the financial statements would be distorted.

Given the nature of the transactions, the above referenced guidance and industry practice, Xcel Energy has determined a net presentation of these RTO transactions is appropriate. Typically, hourly settlements result in net purchases of energy from the system and are classified as cost of sales. Less frequently, Xcel Energy is a net seller of energy to the system and associated hourly amounts are classified as electric revenue.

Xcel Energy’s wholesale sales to third parties facilitated by RTOs totaled $152 million, $45 million and $50 million in 2014, 2013 and 2012, respectively. Related costs of production, RTO charges and other costs of sales totaled $115 million, $30 million and $36 million in 2014, 2013 and 2012, respectively. Consistent with the guidance of ASC 605-45, as Xcel Energy is the primary obligor (responsible for providing the product or service desired by the customer) and produces or procures the energy (changes or performs part of the service) in the transactions, it is appropriate that sales of energy to end customers and associated costs, including amounts related to wholesale transactions executed in RTO markets, are recorded on a gross basis.

RECs, page 95

2. We note that you record REC’s as inventory at cost and that you either purchase them or acquire them in the course of generation. Please address the following comments pertaining to your RECs:


•	Quantify for us the impact of REC’s on your consolidated financial statements for each year presented.


•	Clarify for us how you differentiate the sales of REC’s reflected in revenues on a gross basis from the sales of REC’s for “trading purposes” reflected on a net basis. In other words, explain to us how you distinguish a “trading” REC from a “non-trading” REC.

Response:

Xcel Energy’s consolidated balance sheets include $4 million and $2 million of RECs at Dec. 31, 2014 and 2013, respectively. The Company’s consolidated statements of income reflect revenues of $5 million, $33 million and $27 million for sales of RECs for the years ended Dec. 31, 2014, 2013 and 2012, respectively. The cost of the RECs, transaction costs associated with the sales and amounts due customers under margin-sharing mechanisms ordered by state regulators are recorded in electric fuel and purchased power expense. Electric fuel and purchased power expense associated with RECs sold was approximately $3 million, $26 million and $22 million for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

Xcel Energy obtains RECs through operating renewable generating facilities and under the terms of most renewable energy purchased power agreements. RECs obtained in this manner or purchased for compliance represent the Company's “non-trading” RECs. The Company considers “trading” REC transactions to be those that involve speculative acquisitions of RECs for future sale. When Xcel Energy purchases a REC for trading purposes, the REC is designated in the Company’s internal system as a trading instrument. Xcel Energy has not entered into any transactions involving trading RECs in recent years.

Note 12. Rate Matters, page 129

3. We note from your Form 8-K filed on March 9, 2015 that the MPUC voted to disallow recovery of costs related to your Monticello LCM/EPU project and that you expect to record a charge of approximately $125 million during the first quarter of 2015. Considering the recovery disallowance recommendations of the DOC and OAG during 2014 along with the February 2015 ALJ recovery disallowance proposal, please tell us in more detail why no charges were recorded during fiscal 2014 related to the Monticello prudence investigation.

Response:

Xcel Energy records a disallowance when it becomes probable that part of the cost of a recently completed plant will be disallowed and the amount of the disallowance is estimable. In practice, a rate order is generally considered a “confirming event,” and in circumstances where significant uncertainty exists and a final resolution cannot be predicted, a rate order may be required before a utility records a disallowance. The Company believes it is common for utilities to not record a disallowance prior to the receipt of a rate order on the basis that the loss is not probable and/or reasonably estimable. Xcel Energy did not believe a loss related to the Monticello LCM/EPU project was probable and/or reasonably estimable until March 6, 2015, when the Minnesota Public Utilities Commission (MPUC) issued its preliminary decision in this matter.

The following information is intended to provide a background of the project, an overview of the prudence investigation, the positions of the intervenors, Administrative Law Judge (ALJ) and Xcel Energy, the authoritative guidance used for financial reporting and further details of the March 2015 preliminary decision.

Background

In 2008, the MPUC approved two certificates of needs (CNs) related to changes at the Company’s Monticello nuclear generating plant. The first CN requested approval of a 20-year extension of the plant’s operating license known as life cycle management (LCM). The second CN requested approval of an expansion of output capacity at the plant by 71 megawatts, or 12 percent, referred to as the extended power uprate (EPU).

The MPUC approval of the EPU CN authorized the resource need for additional capacity but did not include or require approval of a project cost estimate. However, project expenditures were initially estimated at approximately $320 million, excluding Allowance for Funds Used During Construction (AFUDC), in Xcel Energy’s 2008 filings. Estimated capital expenditures for the EPU portion of the integrated project were also discussed in the EPU CN filing and estimated at approximately $133 million (41.5 percent) based on an allocation applied to the total $320 million LCM/EPU estimate. Final capitalized project costs for the Monticello LCM/EPU project were approximately $748 million, including AFUDC.

Prudence Investigation

In 2013, the MPUC initiated an investigation to determine whether the costs for the Monticello LCM/EPU project were prudent.

The following is a chronology of events related to the MPUC prudence investigation and a reference to the filing which disclosed the event:



Date	Description	Filing
Aug. 2, 2013	Disclosure of total cost estimate of $650 million, excluding AFUDC	June 30, 2013 Form 10-Q
Sept. 3, 2013	MPUC initiation of prudence investigation	Sept. 30, 2013 Form 10-Q
Oct. 18, 2013	Xcel Energy direct testimony	Sept. 30, 2013 Form 10-Q
Oct. 25, 2013	Xcel Energy initial disclosure of prudence investigation	Sept. 30, 2013 Form 10-Q
July 2, 2014	Department of Commerce (DOC) direct testimony	June 30, 2014, Form 10-Q
Aug. 26, 2014	Xcel Energy rebuttal	Sept. 30, 2014 Form 10-Q
Aug. 26, 2014	Office of Attorney General (OAG) rebuttal	Sept. 30, 2014 Form 10-Q
Sept. 19, 2014	Xcel Energy, DOC and OAG surrebuttal	Sept. 30, 2014 Form 10-Q
Feb. 2, 2015	ALJ findings of fact, conclusions of law and recommendations	Dec. 31, 2014 Form 10-K
Feb. 12, 2015	Exceptions filed to the ALJ report	Dec. 31, 2014 Form 10-K
Feb. 17, 2015	Reply exceptions to the ALJ report	Dec. 31, 2014 Form 10-K
Feb. 20, 2015	Xcel Energy Form 10-K filing	Dec. 31, 2014 Form 10-K
March 3 & 6, 2015	MPUC hearing and deliberation	March 6, 2015 Form 8-K
March 6, 2015	MPUC oral decision	March 6, 2015 Form 8-K

In October 2013, Xcel Energy filed a summary report and witness testimony to support the prudence of the incurred cost, citing the increase in the costs to be attributable to the following three factors:


1)	The original estimate was based on a high-level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design;


2)	Implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces as well as Xcel Energy’s and its vendors’ ability to attract and retain experienced workers; and


3)	Additional Nuclear Regulatory Commission licensing related requests over the five-plus year application process.

Minnesota Department of Commerce’ Recommendation

In July 2014, the DOC filed its testimony and recommendation regarding the prudence investigation. Although direct testimony of a DOC witness stated that “the combined LCM/EPU is overwhelmingly cost effective as a whole,” it was the DOC’s recommendation that approximately $71.4 million of Minnesota jurisdiction project costs, including expenditures and associated AFUDC, were not prudent and should be disallowed.

The DOC’s basis for determining the disallowance was predicated upon alleged insufficient planning and cost allocation and project segregation of the LCM/EPU costs. The DOC stated Xcel Energy should have more effectively estimated initial project costs required to achieve additional capacity (i.e., EPU costs). The DOC also estimated that approximately 85 percent of the total costs were associated with components required solely to achieve the EPU. In the event that the Company had known the ultimate costs at the outset and created an allocation that assigned nearly all of the costs of the combined effort to the EPU, the DOC indicated they would not have recommended the project.

Xcel Energy’s Response

Xcel Energy argued that it is not enough for other parties simply to disagree with the position or speculate that costs are too high; rather, it is incumbent upon the parties to submit competent and probative evidence to support their claims. It is the Company’s position that the DOC’s interpretation of prudence of actions, updated to reflect the actual costs and timing (outcomes of those decisions), effectively amends the prudent investment standard to incorporate a retroactive review performed as if an entity could accurately predict the future with respect to complex project implementations. Xcel Energy considered the DOC’s approach to be inconsistent with MPUC precedent related to prudency (i.e., use of only facts known or reasonably knowable at the time a decision is made). The Company also asserted that the deviation in costs was consistent with similar upgrade projects undertaken by other utilities.

The DOC’s position that the LCM and EPU were separate initiatives did not recognize the manner in which the Monticello LCM/EPU project was implemented or the combined nature of the benefit to customers. Minnesota legislation was amended in 2003, creating the ability to pursue license renewal seven years prior to the expiration of Monticello’s operating license. Xcel Energy initially developed the LCM/EPU initiative in 2004, which was a very different environment with respect to energy economics. During that period, the Company was projecting high forecasted demand and natural gas prices, and had limited time to meet those needs and mitigate price volatility through additional base-load resources. In addition to facing the potential for a significant capacity deficit in a high-priced energy market, Xcel Energy also received the MPUC’s 2004 Resource Plan order directing the Company to expedite a plan. As market conditions had not changed prior to the 2008 approval of the CNs, the Monticello LCM/EPU project, as an integrated initiative, remained the preferred option.

Finally, in regard to the allocation of costs, Xcel Energy believes that if a thorough study was performed to determine the allocation of project costs between the LCM and EPU, an allocation much less than the DOC’s 85 percent would be applied to the EPU and the DOC’s prudence analysis would be discredited. Based on the break-even analysis supplied by the DOC, the next-best generating resource alternative to the EPU would have been more economical only if more than approximately 73 percent of the combined LCM/EPU project’s costs were allocable to the EPU. Overstating the proportion of costs allocable to the EPU was necessary to substantiate the disallowance proposed by the DOC.

The DOC witness supporting an 85 percent allocation to the EPU had recently testified that Florida Power and Light (FPL) experienced a similar fact pattern of modifications to initial plans and exceeded initial budget estimates when completing LCM/EPU projects at five of its nuclear units. In the FPL case, the witness allocated 100 percent of the LCM/EPU project costs to the LCM component, underlying a conclusion that FPL was imprudent and a recommendation that $200 million of costs be disallowed. The Florida commission authorized full recovery of the FPL project costs, concluding that no supporting evidence was provided to substantiate the position.

Office of Attorney General’s Recommendation

In August 2014, the OAG filed rebuttal testimony and recommended a disallowance of recovery of $321 million for all jurisdictions (based on a total capitalized cost of $748 million) and no return on $107 million. The recommended disallowance was primarily based on unsubstantiated criticism of Xcel Energy’s management of the project.

Xcel Energy’s Rebuttal

The Company filed rebuttal testimony in August 2014, affirming that the plant is cost-effective for customers and the overall project benefits include providing carbon-free generation through a life extension and uprate of the plant for an installed capacity of approximately $1,000 per kilowatt. As no party disagreed with the fact that the project, viewed as a whole, was “overwhelmingly” cost-effective, and because the OAG’s recommendation disallowed more costs than the overrun itself, the OAG’s recommendation was not considered credible.

Administrative Law Judge’s Recommendation

On Feb. 2, 2015, the ALJ filed his recommendation with the MPUC, with the following findings:


1.	Found that Xcel Energy initially represented that the costs of the LCM to extend the life of the plant would be $135 million in 2005 dollars and that the costs for the EPU to upgrade the capacity of the plant would be $133 million in 2008 dollars, for a total in 2014 dollars of $346 million;


2.	Found that, based on information from March 31, 2014, total estimated project costs were $748 million, including financing costs to that date, amounting to $402 million in costs that exceeded Xcel Energy’s initial cost estimates;


3.	Found that Xcel Energy failed to demonstrate that the entire $402 million in cost overruns, or any identified part thereof, was reasonable and prudent;


4.	Found that Xcel Energy failed to demonstrate that the cost overruns incurred in the LCM/EPU project were prudently incurred and reasonable;


5.	Found that that the appropriate allocation of total LCM/EPU project costs between LCM costs and EPU costs is 15 percent and 85 percent, respectively;

Recommended disallowance of that portion of EPU-related costs that render the Monticello Plant not cost-effective as of the present and adopt the DOC’s recommendation for a $71.4 million reduction to the capital costs of the Monticello EPU resulting in a $10.2 million revenue requirement downward adjustment for 2015 on a Minnesota jurisdictional basis and ongoing adjustment for the life of the plant stepped down for accumulated depreciation; and


7.	Recommended that this matter be incorporated into the 2013 rate case proceeding.

The ALJ’s position was largely consistent with the DOC recommendation and failed to provide additional evidence or insight. The ALJ cited three fundamental short-comings with the evidence submitted.

Xcel Energy’s Exception

The Company filed exceptions to the ALJ’s report on Feb. 17, 2015 and addressed the three items as summarized below:

First, the scope was not originally assessed properly, which directly led to downstream costs. Xcel Energy filed within its exceptions:


•	The ALJ ignored significant testimony regarding the necessity to upgrade the plant. The need to upgrade was outlined in plans predating the CNs and framed the required scope. The condition of the plant was well described in the record and there was no dispute that investment was necessary.

•

With each major scope decision on the four primary components of the project with major overruns, the Company took into consideration reasonable alternatives. Minnesota Court of Appeals precedent states that in a prudence inquiry, the utility is not obligated to demonstrate that it made the best choice at every juncture, but rather that its decisions were within a “zone of reasonableness.” The ALJ’s Report did not address the evidence in the record regarding Xcel Energy’s assessment of alternatives on various scope issues or make a determination whether or not the choices were within the zone of reasonableness.

Second, the ALJ stated that Xcel Energy fast-tracked the project. The Company filed within its exceptions:

•

A reminder to the MPUC that the energy and capacity market at the time the project was approved was drastically different than the present. Capacity was limited and Xcel Energy had identified a significant base-load requirement. In 2006 and 2008 when the CNs were filed, the Company was operating in an environment with high natural gas prices that were forecasted to continue. Additionally, the state passed the Next Generation Act which called on utilities to reduce carbon by 30 percent. Increasing nuclear capacity addressed these concerns. To cast the decision to move forward as unreasonable could only be reached in hindsight. At the time the decision was made, acting more expeditiously than a traditional design, bid and build was justified.

•

To preserve nuclear generation at Monticello, the Company had to move forward with a single project, not two different projects, to achieve maximum value for the rate payers. Taking into consideration the environment that the Company was operating in, and the utilization of the contractors’ expertise, Xcel Energy developed a planned project timeline. The Company did not adopt an overaggressive timeframe that jeopardized the project. Xcel Energy prudently managed the project by rejecting equipment that failed to meet specifications and designs that were inferior and in certain cases viewed as too costly. The Company also delayed the timing of outages and eventually completed the project on the schedule preferred by the parties’ experts.

Third, the ALJ suggested that Xcel Energy’s failure to foresee the ultimate costs was unreasonable and the DOC would have recommended not continuing with the uprate had better information been available. The ALJ can only arrive at such a conclusion by assuming it was reasonably known to the Company that the ultimate cost would be $665 million and, as alleged, project costs were 85 percent attributable to the EPU. In its exceptions, Xcel Energy highlighted why both were inappropriate based on admissions of the DOC’s expert witness and the contradictory logic of the ALJ. As noted above, the allocation of 85 percent of the overall costs to the EPU was a significant weakness in the DOC’s analysis and any reasonable assignment of costs to the EPU would not result in a disallowance.

Overall, the ALJ’s role is to provide hearing and mediation services on behalf of the MPUC, whereby the ALJ controls development of the evidentiary record, and following testimony and evidentiary hearings, makes recommendations to be considered by the MPUC. In cases where there is substantial precedent, the MPUC may adopt an ALJ recommendation. However, the MPUC is not bound to follow an ALJ recommendation and it is not uncommon for the MPUC to deviate from the recommendation of an ALJ. The MPUC has a history of departing from ALJ recommendations regarding rate cases, fuel clause adjustments, rider recoveries, competitive bidding, etc. The alleged basis and size of the DOC’s disallowance recommendation were unprecedented. Because of the flaws in the DOC’s logic, that was adopted by the ALJ, a substantial opportunity for Xcel Energy was created and one that could have caused the MPUC to view the ALJ’s report as an insufficient basis to make any finding of imprudence.

Authoritative and Interpretive Guidance

In regard to accounting recognition, the authoritative guidance for a disallowance of the costs of a recently completed plant is set forth in ASC 980-360 Regulated Operations - Property, Plant and Equipment, and states:

When it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss... If part of the cost is explicitly, but indirectly, disallowed (for example, by an explicit disallowance of return on investment on a portion of the plant), an equivalent amount of cost shall be deducted from the reported cost of the plant and recognized as a loss.

Pertaining to dealing with uncertainty in accounting and disclosure for a potential disallowance, Accounting for Public Utilities, by Robert L. Hahne and Gregory E. Aliff, with contributions from Deloitte & Touche LLP, provides this interpretive guidance:

The accounting for a direct disallowance is straightforward in theory. The difficulty in applying ASC 980-360 to direct disallowances arises in determining when the disallowance should be recognized. If the regulator has already disallowed recovery, the decision is not difficult (unless the courts may reverse the decision). The FASB has stated that a write-off may be appropriate before a rate order is issued if the write-off is probable, based on factors such as a statute or historical treatment. That is, if some write-off is possible, the estimated loss (or the minimum end of the probable range of loss) should be written-off immediately.

However, when a utility has recently completed construction on a plant and the utility is waiting for a rate decision, the accounting is often not clear. Sometimes a regulator may be so unpredictable that, until a regulator renders a final decision, the utility cannot reasonably estimate the probable non-recoverable amounts. In instances when the disallowed cost can be estimated, it should be written-off.

In practice a rate order is generally considered a “confirming event” as to when a write-off related to an abandonment or a disallowance is required. Utilities often do not record a disallowance before receipt of a rate order on the basis that the loss is not reasonably estimable.

Xcel Energy also utilized ASC 450-20 Contingencies - Loss Contingencies in assessing the financial reporting requirements. Probable loss contingencies are recorded in accordance with ASC 450-20-25-2. Reasonably possible loss contingencies are evaluated to assess whether an estimate of possible loss or range can be made and disclosed in accordance with ASC 450-20-50-4.

At Feb. 20, 2015 (the date the financial statements were filed), an inordinate amount of uncertainty existed. The Company viewed its position as supportable and concluded the ALJ had not properly considered substantial and probative evidence. Moreover, the MPUC was not bound to follow, and in fact did not follow, the ALJ’s recommendation. Although Xcel Energy utilized its understanding and historical experience with laws and statutes pertaining to prudence in making a probability determination, the fact that no jurisdictional history of rulings pertaining to items of this nature/complexity/magnitude existed only compounded the uncertainty. Given the underlying facts and circumstances, the Company did not consider a loss associated with the Monticello prudence investigation to be probable.

Xcel Energy determined the range of a possible loss was zero (Xcel Energy’s position) to a maximum amount of the OAG’s recommendation ($321 million disallowance for all jurisdictions and no return on $107 million). No amount within that range was presumed to provide a better estimate than any other amount. Disclosure of the background of the investigation, including the quantitative (i.e., range) and qualitative positions of the parties, as well as the remaining scheduled procedures, were provided in Xcel Energy’s Form 10-K for the fiscal year ended Dec. 31, 2014. In addition, the Company filed multiple Form 8-Ks to update investors as to the status of the investigation and disclosed relevant information regarding the investigation in its quarterly and annual filings beginning in the third quarter of 2013.

ASC 855 Subsequent Events prescribes the accounting for events and transactions that occur after the balance sheet date but before entities issue financial statements. Xcel Energy determined that the ALJ decision received in Feb. 2015 and the Company’s rebuttal position both related to a condition that existed at the balance sheet date. These matters were appropriately considered and disclosed.

The Company filed a Form 8-K in March 2015 to disclose the MPUC had voted to allow full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but to allow recovery of the remaining $333 million of costs with no return. Xcel Energy also disclosed in the Form 8-K an estimated loss of approximately $125 million would be recorded in the first quarter of 2015. The MPUC’s preliminary decision did not result in a direct disallowance, but rather an indirect disallowance. The decision did not align with, or conform to, the positions of the intervenors, the ALJ or Xcel Energy. The MPUC’s deviation further demonstrates the uncertainty that existed at the time the Company's Form 10-K for the fiscal year ended Dec. 31, 2014 was filed.

Although the MPUC decision was orally delivered and a final written order is currently pending, written orders of the MPUC have historically been consistent with verbal decisions. As such, the MPUC’s March 2015 verbal decision was considered a confirming event, and a probable and estimable disallowance was required to be recognized in the first quarter of 2015.

Conclusion

Xcel Energy considered the recommendations of the DOC, OAG and ALJ to be inconsistent and lack requisite support. These positions were not considered confirming events, but rather additional factors (subject to revision or rejection by the MPUC) to be assessed within the context of the entire body of evidence presented in regard to the prudence investigation. As of Feb. 20, 2015, Xcel Energy continued to assert that the costs incurred were prudent and the evidence submitted by the Company to the MPUC supported this assertion to a much greater extent than the unsubstantiated evidence provided by the intervenors and ALJ.

Based on the facts and circumstances, Xcel Energy concluded a disallowance associated with the Monticello LCM/EPU project was not probable or reasonably estimable as of Dec. 31, 2014.

Note 13. Commitments and Contingencies, page 139

4. We note from your table on page 152 that you recorded a $128 million cash flow revision adjustment to your gas transmission and distribution asset retirement obligation balance during fiscal 2014. Please tell us and consider disclosing in future filings the reasons for this and other material ARO adjustments.

Response:

The cash flow revision related to the gas transmission and distribution asset retirement obligation was primarily attributable to changes in the estimated timing and costs associated with retiring (i.e., capping and purging) gas mains and individual lines. Xcel Energy has launched an accelerated main replacement program in Colorado and Minnesota which directly impacts the timing of retirement activities. Excavation cost estimates also increased based on updated information, including the impact of the expedited schedule.

In future filings, the Company will revise its disclosure in substantially the same form as follows:

In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes to estimated nuclear production decommissioning primarily relate to the triennial filing made to the MPUC in December 2014. See additional information in Note 14. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.

Note 14. Nuclear Obligations, page 155

5. We note your disclosure on page 156 summarizing the funded status of your nuclear decommissioning obligation and note that the amounts were prepared on a regulatory basis and are not recorded in your financial statements for the ARO. Please tell us the primary differences between the amounts reported in this table for regulatory purposes and the amounts recorded in your financial statements. Also tell us, and revise your disclosure to clarify in future filings, why management believes it is useful to investors to present this table on a regulatory basis.

Response:

The difference between the nuclear decommissioning obligation presented on a regulatory basis and the ARO recorded in accordance with U.S. GAAP (i.e., ASC 410 Asset Retirement and Environmental Obligations) is primarily due to differences in the treatment of the applied discount rates, certain operating and maintenance expenses, market risk premium and in the cost studies utilized.

First, the most significant difference relates to the discount rate. The applied discount rate for regulatory purposes is agreed to by the MPUC, resulting in the measurement of the estimated ARO balance at the current Treasury rate adjusted for the Company’s credit risk. For financial reporting purposes the estimation of AROs does not factor in changes in interest rates from the period the ARO was originally established, except in relation to incremental revisions in accordance with the provision of ASC 410-20-35-8. The discount rate used for regulatory purposes was 2.8 percent versus a 5.1 percent average applied rate for financial reporting purposes.

Second, the cost projections used by the MPUC to determine rate recovery include certain items not included in the estimated U.S. GAAP ARO amounts, such as operating and maintenance costs associated with future interim storage of spent fuel. Xcel Energy has a legal obligation to remove nuclear fuel storage structures and perform site restoration. There are no legal obligations associated with the operation of the site until the United States Department of Energy takes possession of and removes spent fuel to permanent storage. In accordance with ASC 410-20-15-3 (h), obligations associated with the maintenance, rather than retirement of a long-lived asset, are excluded from the ARO calculation. Therefore, costs such as those associated with interim storage of spent fuel are not included in the ARO amounts recorded in the financial statements.

Third, the ARO amounts recorded in the financial statements include a risk premium which is not a regulatory basis requirement. U.S. GAAP also requires the use of the best information available. In years such as 2014, Xcel Energy used the current triennial nuclear decommissioning study subject to MPUC approval to estimate the ARO. However, for regulatory purposes the Company continued to use the study previously approved by the MPUC.

The ARO recorded in accordance with U.S. GAAP and the estimated nuclear decommissioning obligation utilized by the MPUC to establish rates to recover future costs differ due to the reasons outlined above. The regulatory basis information enables the Company to disclose amounts consistent with those previously communicated to the MPUC and is useful to a user of the financial statements in assessing future cash flows, including revenue requirements.

The following table provides a reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with U.S. GAAP:



(Thousands of Dollars)	Dec. 31, 2014	Dec. 31, 2013
Discounted decommissioning cost obligation - regulated basis	$ 3,536,818	$ 2,366,238
Differences in discount rate and market risk premium	(1,275,101)	(410,675)
Operating and maintenance costs not included for U.S. GAAP	(547,135)	(327,265)
Differences in cost studies (2011 versus 2014)	323,365	0
Nuclear production decommissioning ARO - U.S. GAAP	$ 2,037,947	$ 1,628,298

In future filings, Xcel Energy will revise its disclosure to include the additional disclosure in substantially the form as follows:

Calculations and data used by the regulator in approving company rates are useful in assessing future cash flows. The regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.

In connection with the above response to the Staff’s comments, we acknowledge that:

the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please direct any further comments or questions to me at (612) 215-4560.

Very truly yours,

/s/ Teresa S. Madden

Teresa S. Madden

Executive Vice President and Chief Financial Officer