form10q.htm

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Net income	$	95,407		$	71,018		$	188,692		$	167,648

Other comprehensive (loss) income

Derivative instruments:
Net fair value (decrease) increase, net of tax of $(11,485), $(9), $(3,513) and $51, respectively		(18,757	)		(16	)		(5,737	)		82
Reclassification of gains to net income, net of tax of $(230), $(238), $(460) and $(457), respectively		(376	)		(389	)		(751	)		(746	)
		(19,133	)		(405	)		(6,488	)		(664	)

Other comprehensive loss		(19,133	)		(405	)		(6,488	)		(664	)
Comprehensive income	$	76,274		$	70,613		$	182,204		$	166,984

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2012			2011
Operating activities
Net income	$	188,692		$	167,648
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		166,460			162,890
Demand side management program amortization		2,785			5,091
Deferred income taxes		117,034			89,067
Amortization of investment tax credits		(1,303	)		(1,335	)
Allowance for equity funds used during construction		(6,274	)		(3,417	)
Net derivative losses		5,953			19,310
Changes in operating assets and liabilities:
Accounts receivable		57,355			35,878
Accrued unbilled revenues		100,953			73,003
Inventories		69,268			20,067
Prepayments and other		(34,380	)		28,819
Accounts payable		(106,008	)		(37,276	)
Net regulatory assets and liabilities		(33,991	)		(32,457	)
Other current liabilities		(54,416	)		(15,066	)
Pension and other employee benefit obligations		(38,190	)		(58,054	)
Change in other noncurrent assets		(7,450	)		(162	)
Change in other noncurrent liabilities		(4,737	)		(11,442	)
Net cash provided by operating activities		421,751			442,564

Investing activities
Utility capital/construction expenditures		(382,676	)		(278,282	)
Allowance for equity funds used during construction		6,274			3,417
Investments in utility money pool arrangement		(610,000	)		(3,300	)
Repayments from utility money pool arrangement		662,000			3,300
Net cash used in investing activities		(324,402	)		(274,865	)

Financing activities
Proceeds from (repayments of) short-term borrowings, net		5,000			(120,400	)
Borrowings under utility money pool arrangement		19,000			176,500
Repayments under utility money pool arrangement		(14,000	)		(176,500	)
Capital contributions from parent		28,122			76,221
Dividends paid to parent		(134,004	)		(135,047	)
Net cash used in financing activities		(95,882	)		(179,226	)

Net change in cash and cash equivalents		1,467			(11,527	)
Cash and cash equivalents at beginning of period		3,763			32,912
Cash and cash equivalents at end of period	$	5,230		$	21,385

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(90,642	)	$	(86,865	)
Cash (paid) received for income taxes, net		(33,342	)		35,043
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	58,967		$	88,364

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	June 30, 2012			Dec. 31, 2011
Assets
Current assets
Cash and cash equivalents	$	5,230		$	3,763
Accounts receivable, net		230,090			317,039
Accounts receivable from affiliates		41,657			12,063
Investments in utility money pool arrangement		-			52,000
Accrued unbilled revenues		203,591			304,544
Inventories		184,729			253,997
Regulatory assets		143,654			196,311
Deferred income taxes		21,952			33,349
Derivative instruments		5,565			4,930
Prepayments and other		53,884			19,504
Total current assets		890,352			1,197,500

Property, plant and equipment, net		9,683,409			9,475,571

Other assets
Regulatory assets		789,364			809,011
Derivative instruments		12,305			15,357
Other		42,010			36,066
Total other assets		843,679			860,434
Total assets	$	11,417,440		$	11,533,505

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	855,954		$	605,633
Short-term debt		5,000			-
Borrowings under utility money pool arrangement		5,000			-
Accounts payable		275,195			362,580
Accounts payable to affiliates		29,621			48,371
Regulatory liabilities		34,950			68,809
Taxes accrued		66,359			116,376
Accrued interest		53,549			53,749
Dividends payable to parent		66,497			66,926
Derivative instruments		47,576			85,518
Other		67,525			75,671
Total current liabilities		1,507,226			1,483,633

Deferred credits and other liabilities
Deferred income taxes		1,881,258			1,775,448
Deferred investment tax credits		43,422			44,725
Regulatory liabilities		420,396			444,442
Asset retirement obligations		43,395			42,207
Derivative instruments		33,757			38,325
Customer advances		221,752			226,097
Pension and employee benefit obligations		184,361			222,707
Other		71,394			69,561
Total deferred credits and other liabilities		2,899,735			2,863,512

Commitments and contingencies
Capitalization
Long-term debt		2,628,010			2,880,642
Common stock – 100 shares authorized at $0.01 par value; 100 shares outstanding at June 30, 2012 and Dec. 31, 2011		-			-
Additional paid in capital		3,344,508			3,316,386
Retained earnings		1,056,826			1,001,709
Accumulated other comprehensive loss		(18,865	)		(12,377	)
Total common stockholder's equity		4,382,469			4,305,718
Total liabilities and equity	$	11,417,440		$	11,533,505

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of June 30, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2012 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011, filed with the SEC on Feb. 27, 2012. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.	Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity. These requirements were effective for interim and annual periods beginning after Dec. 15, 2011. PSCo implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements. For required fair value measurement disclosures, see Note 8.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These requirements were effective for interim and annual periods beginning after Dec. 15, 2011. PSCo implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. PSCo does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	254,608		$	341,737
Less allowance for bad debts		(24,518	)		(24,698	)
	$	230,090		$	317,039
Inventories
Materials and supplies	$	53,946		$	53,318
Fuel		77,674			94,874
Natural gas		53,109			105,805
	$	184,729		$	253,997
Property, plant and equipment, net
Electric plant	$	9,654,745		$	9,469,434
Natural gas plant		2,507,178			2,456,275
Common and other property		736,774			763,513
Plant to be retired (a)		112,823			151,184
Construction work in progress		392,347			242,095
Total property, plant and equipment		13,403,867			13,082,501
Less accumulated depreciation		(3,720,458	)		(3,606,930	)
	$	9,683,409		$	9,475,571

(a)

In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, and in May 2012, Cherokee Unit 1 was retired. Amounts are presented net of accumulated depreciation.

4.	Income Taxes

Except to the extent noted below, the circumstances set forth in Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012. As of June 30, 2012, there was no federal income tax audit in progress.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2012, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. As of June 30, 2012, there were no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2012		Dec. 31, 2011
Unrecognized tax benefit — Permanent tax positions	$	0.5	$	0.5
Unrecognized tax benefit — Temporary tax positions		10.1		10.9
Unrecognized tax benefit balance	$	10.6	$	11.4

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The unrecognized tax benefit balance was reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)		June 30, 2012				Dec. 31, 2011
NOL and tax credit carryforwards		$	(3.2	)		$	(3.7	)

It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the Internal Revenue Service and state audits resume. At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2012 and Dec. 31, 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2012 or Dec. 31, 2011.

5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Recently Concluded Regulatory Proceedings — CPUC

2011 Electric Rate Case — In November 2011, PSCo filed a request with the CPUC to increase Colorado retail electric rates by $141.9 million. The request was based on a 2012 forecast test year, a 10.75 percent return on equity (ROE), an electric rate base of $5.4 billion and an equity ratio of 56 percent.

On April 26, 2012, the CPUC approved a comprehensive multi-year settlement agreement, which covers 2012 through 2014. Key terms of the agreement include the following:

PSCo would implement an annual electric rate increase of $73 million in 2012. The rate increase was effective on May 1, 2012. In addition, PSCo will implement incremental electric rate increases of $16 million on Jan. 1, 2013 and $25 million on Jan. 1, 2014. These rate increases are net of the shift of the costs from the purchased capacity cost adjustment and the transmission cost adjustment clauses to base rates.

·	The settlement reflects an authorized ROE of 10 percent and an equity ratio of 56 percent.

For 2012 through 2014, incremental property taxes in excess of $76.7 million (2010-2011 historic test year property taxes) will be deferred over a three-year period with the amortization effective the first year after the deferral. To the extent that PSCo is successful in gaining the manufacturer’s sales tax refund as a result of the sales tax lawsuit currently pending in the Colorado Supreme Court, PSCo will credit such refunds first against legal fees incurred to obtain the refund and then against the deferred property tax balances outstanding at the end of the 2014.

·	The signing parties agreed to implement an earnings test, in which customers and shareholders will share weather normalized earnings above an ROE of 10 percent. The sharing mechanism is as follows:

ROE	Shareholders			Customers
> 10.0% < 10.2%		40	%		60	%
> 10.2% < 10.5%		50			50
> 10.5%		-			100

PSCo agreed that it will not file for an electric rate increase that would take effect prior to Jan. 1, 2015, provided that net revenue requirements increases or decreases in excess of $10 million caused by changes in tax law, government mandates, or natural disasters may be deferred or recovered through a modified rate adjustment. In the event normalized base revenues in either 2012 or 2013 are 2.0 percent below 2011 actual levels adjusted to reflect the rate increases allowed for 2012 and 2013, PSCo has the right to an additional rate adjustment in the next year for 50 percent of the shortfall. The parties acknowledged that PSCo may file an electric rate increase as early as May 1, 2014, so long as no rate increase takes effect on either an interim or permanent basis prior to Jan. 1, 2015.

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Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

2011 Wholesale Electric Rate Case — In February 2011, PSCo filed with the FERC to change Colorado wholesale electric rates to formula based rates with an expected annual increase of $16.1 million for 2011. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a rate base of $407.4 million and an equity ratio of 57.1 percent. The formula rate would be estimated each year for the following year and then trued-up to actual costs after the conclusion of the calendar year. In September 2011, PSCo implemented an interim rate increase of $7.8 million, subject to refund.

In April 2012, PSCo filed an unopposed settlement agreement with wholesale customers for an annual rate increase of $7.8 million. The primary reasons for the decrease from the original request were a reduction to depreciation expense of $5.8 million and a lower ROE, ranging from 10.1 percent to 10.4 percent. The settlement was approved by the FERC in June 2012.

Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission rates formula from a historic test year formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to Nov. 17, 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

Separately, several wholesale customers filed a complaint with the FERC in June 2012 seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. It is expected that the FERC will consider both matters concurrently.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers beginning in 2011 and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014. The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance. In the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.

In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance. In March 2012, PSCo credited approximately $28.7 million against the RESA regulatory asset balance.

This sharing mechanism will be effective through 2014 to provide the CPUC an opportunity to review the framework and to review evidence regarding actual deliveries in relatively more complex markets such as California.

6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position.

Purchased Power Agreements

Under certain purchased power agreements, PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific purchased power agreements create a variable interest in the associated independent power producing entity.

PSCo had approximately 1,882 megawatts (MW) of capacity under long-term purchased power agreements as of June 30, 2012 and Dec. 31, 2011 with entities that have been determined to be variable interest entities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through the year 2028.

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Guarantees and Indemnifications

In connection with the acquisition of 900 MW of natural gas-fired generation from subsidiaries of Calpine Development Holdings Inc. in 2010, PSCo agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties. The aggregate liability for PSCo pursuant to these indemnities is not subject to a capped dollar amount. The indemnification obligation expires in December 2012. PSCo has not recorded a liability related to this indemnity, and it had no assets held as collateral related to this agreement at June 30, 2012 or Dec. 31, 2011.

Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the U.S. Environmental Protection Agency (EPA) proposed a GHG NSPS for newly constructed power plants. The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired. The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and noted that, pursuant to its general NSPS regulations, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. Xcel Energy submitted comments on the proposed GHG NSPS in June 2012. It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA). It is not known when the EPA will propose new standards for existing sources.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. PSCo believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States. PSCo generating facilities are subject to BART requirements. Individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide, nitrogen oxide and particulate matter (PM) emissions under BART and then set emissions limits for those facilities.

In 2006, the Colorado Air Quality Control Commission (CAQCC) promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. In January 2011, the CAQCC approved a revised regional haze BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements. In March 2012, the EPA proposed to approve the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements. The emission controls are expected to be installed between late 2012 and 2017. PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA emission reduction plan recovery mechanisms or other regulatory mechanisms.

In March 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM. In areas in which PSCo operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard. The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas. PSCo expects the proposed visibility standard would likely be met where PSCo operates power plants based on currently available information. A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014. If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until its final requirements are known.

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Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material effect on PSCo’s consolidated financial position, results of operations, and cash flows.

Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of PSCo, and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In November 2011, oral arguments were presented. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million. While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on PSCo’s consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc. and PSCo. The amount of damages claimed by plaintiffs is unknown. The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit. In March 2012, the U.S. District Court granted this motion for dismissal. In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit. While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on PSCo’s consolidated results of operations, cash flows or financial position. No accrual has been recorded for this matter.

7.	Borrowings and Other Financing Instruments

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. The following table presents commercial paper outstanding for PSCo:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	700		$	700
Amount outstanding at period end		5			-
Average amount outstanding		3			73
Maximum amount outstanding		31			304
Weighted average interest rate, computed on a daily basis		0.31	%		0.37	%
Weighted average interest rate at period end		0.30			N/A

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under the credit agreement. The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, 2012, PSCo had the following committed credit facility available (in millions of dollars):

Credit Facility				Drawn (a)				Available
$	700.0			$	8.0			$	692.0

(a)	Includes outstanding commercial paper and letters of credit.

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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at June 30, 2012 and Dec. 31, 2011.

Amended Credit Agreement — In July 2012, PSCo entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

PSCo has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

Letters of Credit — PSCo uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At June 30, 2012 and Dec. 31, 2011, there were $3.0 million and $4.9 million of letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The following table presents the money pool borrowings for PSCo:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstanding at period end		5			-
Average amount outstanding		-			3
Maximum amount outstanding		5			53
Weighted average interest rate, computed on a daily basis		0.33	%		0.35	%
Weighted average interest rate at period end		0.34			N/A

Long-Term Borrowings — PSCo plans to refinance the current portion of long-term debt coming due in 2012.

8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

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Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Derivative Instruments Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At June 30, 2012, accumulated OCI related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At June 30, 2012, PSCo had unsettled interest rate swaps outstanding with a total notional amount of $250 million. These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel.

At June 30, 2012, PSCo had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and six months ended June 30, 2012 and 2011.

At June 30, 2012, accumulated OCI related to vehicle fuel cash flow hedges included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of any amounts credited to customers under margin-sharing mechanisms.

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The following table details the gross notional amounts of commodity forwards and options at June 30, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	June 30, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		973		1,299
MMBtu of natural gas		6,246		32,053
Gallons of vehicle fuel		225		270

(a)	Amounts are not reflective of net positions in the underlying commodities.

(b)	Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2012 and 2011, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2012
	Fair Value Gains (Losses)					Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:					into Income During the Period from:
	Accumulated					Accumulated					Pre-Tax Gains
	Other			Regulatory		Other			Regulatory		Recognized
	Comprehensive			(Assets) and		Comprehensive			Assets and		During the Period
(Thousands of Dollars)	Loss			Liabilities		Loss			(Liabilities)		in Income
Derivatives designated as cash flow hedges
Interest rate	$	(30,163	)	$	-	$	(582	)(a)	$	-	$	-
Vehicle fuel and other commodity		(79	)		-		(24	)(c)		-		-
Total	$	(30,242	)	$	-	$	(606	)	$	-	$	-

Other derivative instruments
Trading commodity	$	-		$	-	$	-		$	-	$	1	(b)
Natural gas commodity		-			769		-			-		-
Total	$	-		$	769	$	-		$	-	$	1

	Six Months Ended June 30, 2012
	Fair Value Gains (Losses)							Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:							into Income During the Period from:
		Accumulated							Accumulated						Pre-Tax Gains
		Other			Regulatory				Other			Regulatory			(Losses) Recognized
		Comprehensive			(Assets) and				Comprehensive			Assets and			During the Period
(Thousands of Dollars)		Loss			Liabilities				Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate		$	(9,246	)	$	-			$	(1,165	)(a)	$	-		$	-
Vehicle fuel and other commodity			(4	)		-				(46	)(c)		-			-
Total		$	(9,250	)	$	-			$	(1,211	)	$	-		$	-

Other derivative instruments
Trading commodity		$	-		$	-			$	-		$	-		$	1	(b)
Natural gas commodity			-			(6,946	)			-			61,858	(d)		(109	)(b)
Total		$	-		$	(6,946	)		$	-		$	61,858		$	(108	)

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	Three Months Ended June 30, 2011
	Fair Value Gains (Losses)							Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:							into Income During the Period from:
		Accumulated							Accumulated						Pre-Tax Losses
		Other			Regulatory				Other			Regulatory			Recognized
		Comprehensive			(Assets) and				Comprehensive			Assets and			During the Period
(Thousands of Dollars)		Income			Liabilities				Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate		$	-		$	-			$	(582	)(a)	$	-		$	-
Vehicle fuel and other commodity			(43	)		-				(27	)(c)		-			-
Total		$	(43	)	$	-			$	(609	)	$	-		$	-

Other derivative instruments
Trading commodity		$	-		$	-			$	-		$	-		$	(150	)(b)
Natural gas commodity			-			(7,792	)			-			738	(d)		-
Total		$	-		$	(7,792	)		$	-		$	738		$	(150	)

	Six Months Ended June 30, 2011
	Fair Value Gains (Losses)					Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:					into Income During the Period from:
	Accumulated					Accumulated						Pre-Tax Gains
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income		Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-		$	(1,159	)(a)	$	-		$	-
Vehicle fuel and other commodity		133		-			(45	)(c)		-			-
Total	$	133	$	-		$	(1,204	)	$	-		$	-

Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	95	(b)
Natural gas commodity		-		(13,146	)		-			45,220	(d)		-
Total	$	-	$	(13,146	)	$	-		$	45,220		$	95

(a)	Recorded to interest charges.

(b)	Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c)	Recorded to operating and maintenance (O&M) expenses.

(d)	Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2012 and June 30, 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features — Contract provisions of the derivative instruments that PSCo enters into may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit ratings. If the credit ratings of PSCo were downgraded below investment grade, contracts underlying $5.6 million and $6.9 million of derivative instruments in a gross liability position at June 30, 2012 and Dec. 31, 2011, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $8.8 million and $9.2 million, respectively. At June 30, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

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PSCo’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2012 and Dec. 31, 2011.

Recurring Fair Value Measurements — The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012:

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	40	$	-	$	40	$	-		$	40
Other derivative instruments:
Trading commodity		-		6,483		-		6,483		(3,443	)		3,040
Natural gas commodity		-		806		-		806		(37	)		769
Total current derivative assets	$	-	$	7,329	$	-	$	7,329	$	(3,480	)		3,849
Purchased power agreements (a)													1,716
Current derivative instruments												$	5,565
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	26	$	-	$	26	$	-		$	26
Other derivative instruments:
Trading commodity		-		4,624		-		4,624		(1,809	)		2,815
Total noncurrent derivative assets	$	-	$	4,650	$	-	$	4,650	$	(1,809	)		2,841
Purchased power agreements (a)													9,464
Noncurrent derivative instruments												$	12,305

Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	38,876	$	-	$	38,876	$	-		$	38,876
Other derivative instruments:
Trading commodity		-		6,009		-		6,009		(2,737	)		3,272
Natural gas commodity		-		37		-		37		(37	)		-
Total current derivative liabilities	$	-	$	44,922	$	-	$	44,922	$	(2,774	)		42,148
Purchased power agreements (a)													5,428
Current derivative instruments												$	47,576
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	4,152	$	-	$	4,152	$	(1,809	)	$	2,343
Total noncurrent derivative liabilities	$	-	$	4,152	$	-	$	4,152	$	(1,809	)		2,343
Purchased power agreements (a)													31,414
Noncurrent derivative instruments												$	33,757

(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b)

The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	76	$	-	$	76	$	(76	)	$	-
Other derivative instruments:
Trading commodity		-		6,550		-		6,550		(3,712	)		2,838
Total current derivative assets	$	-	$	6,626	$	-	$	6,626	$	(3,788	)		2,838
Purchased power agreements (a)													2,092
Current derivative instruments												$	4,930
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	48	$	-	$	48	$	-		$	48
Other derivative instruments:
Trading commodity		-		8,292		-		8,292		(3,305	)		4,987
Total noncurrent derivative assets	$	-	$	8,340	$	-	$	8,340	$	(3,305	)		5,035
Purchased power agreements (a)													10,322
Noncurrent derivative instruments												$	15,357

Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	29,630	$	-	$	29,630	$	-		$	29,630
Other derivative instruments:
Trading commodity		-		6,076		-		6,076		(2,846	)		3,230
Natural gas commodity		-		54,525		-		54,525		(7,410	)		47,115
Total current derivative liabilities	$	-	$	90,231	$	-	$	90,231	$	(10,256	)		79,975
Purchased power agreements (a)													5,543
Current derivative instruments												$	85,518
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	7,502	$	-	$	7,502	$	(3,305	)	$	4,197
Total noncurrent derivative liabilities	$	-	$	7,502	$	-	$	7,502	$	(3,305	)		4,197
Purchased power agreements (a)													34,128
Noncurrent derivative instruments												$	38,325

(a)

(b)

There were no changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2012 and 2011.

PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for the three and six months ended June 30, 2012 and 2011.

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Fair Value of Long-Term Debt

As of June 30, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2012				Dec. 31, 2011
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,483,964	$	4,005,198	$	3,486,275	$	4,020,083

The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

9.	Other Income, Net

Other income (expense), net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2012			2011			2012			2011
Interest income	$	772		$	1,390		$	1,800		$	2,693
Other nonoperating income		798			742			1,366			1,353
Insurance policy (expense) income		(20	)		106			(584	)		(141	)
Other nonoperating expense		-			(3	)		-			(7	)
Other income, net	$	1,550		$	2,235		$	2,582		$	3,898

10.	Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each reportable segment.

PSCo has the following reportable segments: regulated electric, regulated natural gas and all other.

PSCo’s regulated electric utility segment generates electricity which is transmitted and distributed in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.

·	PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.

·	Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

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	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Three Months Ended June 30, 2012
Operating revenues from external customers	$	714,651	$	147,398	$	7,452	$	-		$	869,501
Intersegment revenues		43		19		-		(62	)		-
Total revenues	$	714,694	$	147,417	$	7,452	$	(62	)	$	869,501
Net income	$	88,807	$	5,529	$	1,071	$	-		$	95,407

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Three Months Ended June 30, 2011
Operating revenues from external customers	$	749,791	$	174,730	$	8,579	$	-		$	933,100
Intersegment revenues		70		173		-		(243	)		-
Total revenues	$	749,861	$	174,903	$	8,579	$	(243	)	$	933,100
Net income	$	66,801	$	2,661	$	1,556	$	-		$	71,018

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Six Months Ended June 30, 2012
Operating revenues from external customers	$	1,396,930	$	530,402	$	18,221	$	-		$	1,945,553
Intersegment revenues		135		74		-		(209	)		-
Total revenues	$	1,397,065	$	530,476	$	18,221	$	(209	)	$	1,945,553
Net income	$	150,140	$	33,839	$	4,713	$	-		$	188,692

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Six Months Ended June 30, 2011
Operating revenues from external customers	$	1,453,944	$	602,921	$	20,682	$	-		$	2,077,547
Intersegment revenues		184		219		-		(403	)		-
Total revenues	$	1,454,128	$	603,140	$	20,682	$	(403	)	$	2,077,547
Net income	$	132,516	$	31,539	$	3,593	$	-		$	167,648

11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2012			2011			2012			2011
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,863		$	4,409		$	590		$	815
Interest cost		12,929			13,203			6,122			6,961
Expected return on plan assets		(16,416	)		(17,011	)		(6,258	)		(7,012	)
Amortization of transition obligation		-			-			2,751			2,751
Amortization of prior service cost (credit)		57			56			(1,287	)		(729	)
Amortization of net loss		8,795			7,314			2,860			2,188
Net periodic benefit cost		11,228			7,971			4,778			4,974
Additional cost recognized due to the effects of regulation		-			-			973			973
Net benefit cost recognized for financial reporting	$	11,228		$	7,971		$	5,751		$	5,947

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	Six Months Ended June 30
	2012			2011			2012			2011
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	11,360		$	8,863		$	1,413		$	1,813
Interest cost		25,553			26,117			12,264			14,196
Expected return on plan assets		(32,651	)		(33,973	)		(12,528	)		(13,981	)
Amortization of transition obligation		-			-			5,502			5,502
Amortization of prior service cost (credit)		114			111			(2,575	)		(1,457	)
Amortization of net loss		17,100			14,063			5,464			4,471
Net periodic benefit cost		21,476			15,181			9,540			10,544
Additional cost recognized due to the effects of regulation		-			-			1,946			1,946
Net benefit cost recognized for financial reporting	$	21,476		$	15,181		$	11,486		$	12,490

In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $41.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2012.

In June 2012, to manage volatility in equity pricing within the pension master trust, Xcel Energy entered into equity collar contracts with a net-zero cost at initiation on a portion of the equity securities. The equity collar strategy is designed to reduce potential equity losses while limiting gains, resulting in lower equity volatility for the pension plans. At June 30, 2012, the mark-to-market value of these arrangements was not material to the value of the pension trust assets. These arrangements will expire in December 2012.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for PSCo is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on PSCo’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of PSCo and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of slow down in the U.S. economy or delay in growth recovery; actions of credit rating agencies; trade, fiscal, taxation and environmental policies in areas where PSCo has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2011, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

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Results of Operations

PSCo’s net income was approximately $188.7 million for the six months ended June 30, 2012, compared with approximately $167.6 million for the same period in 2011. The increase is primarily due to an electric rate increase effective in May 2012, lower O&M expenses and the impact of warmer summer weather. The increase was partially offset by decreased wholesale revenue due to the expiration of a long-term wholesale power agreement with Black Hills Corp.

Electric Revenues and Margin

Electric revenues, fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2012				2011
Electric revenues		$	1,397			$	1,454
Electric fuel and purchased power			(606	)			(676	)
Electric margin		$	791			$	778

The following tables summarize the components of the changes in electric revenues and margin for the six months ended June 30:

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Fuel and purchased power cost recovery	$	(58	)
Firm wholesale (a)		(20	)
Trading, including renewable energy credit sales		(15	)
Retail rate increase		12
Estimated impact of weather		11
DSM incentive		6
Sales mix		4
Other, net		3
Total decrease in electric revenues	$	(57	)

(a)	Decrease is primarily due to the expiration of a long-term wholesale power agreement with Black Hills Corp.

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Retail rate increase	$	12
Estimated impact of weather		11
DSM incentive		6
Sales mix		4
Firm wholesale (a)		(18	)
Trading, including renewable energy credit sales		(5	)
Other, net		3
Total increase in electric margin	$	13

(a)	Decrease is primarily due to the expiration of a long-term wholesale power agreement with Black Hills Corp.

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Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details the natural gas revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2012				2011
Natural gas revenues		$	530			$	603
Cost of natural gas sold and transported			(314	)			(399	)
Natural gas margin		$	216			$	204

The following tables summarize the components of the changes in natural gas revenues and margin for the six months ended June 30:

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(85	)
Estimated impact of weather		(9	)
Transport sales		(2	)
DSM revenue		(1	)
Pipeline system integrity adjustment rider		11
Retail rate increase		7
Return on gas in storage		4
DSM incentive		2
Total decrease in natural gas revenues	$	(73	)

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Pipeline system integrity adjustment rider	$	11
Retail rate increase		7
Return on gas in storage		4
DSM incentive		2
Estimated impact of weather		(9	)
Transport sales		(2	)
DSM revenue		(1	)
Total increase in natural gas margin	$	12

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased by $8.9 million, or 2.5 percent, for the six months ended June 30, 2012, compared with the same period in 2011. The following summarizes the changes in O&M expenses:

(Millions of Dollars)	2012 vs. 2011
Lower plant generation costs		(9	)
Lower consulting costs		(3	)
Lower labor costs		(3	)
Pipeline system integrity costs		10
Higher employee benefit costs		8
Other, net (including management cost savings initiatives)		(12	)
Total decrease in operating and maintenance expenses	$	(9	)

Lower plant generation costs are attributable to a higher level of scheduled overhaul work in 2011.

Higher pipeline system integrity costs related to verification and testing natural gas pipeline integrity. These costs are recovered through a rider in Colorado.

Higher employee benefit costs are primarily due to higher pension expense.

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Depreciation and Amortization — Depreciation and amortization expense increased by approximately $3.5 million, or 2.2 percent, for the six months ended June 30, 2012, compared with the same period for 2011. The increase is due to normal system expansion.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by $4.0 million for the six months ended June 30, 2012, compared with the same period in 2011. The increase is primarily due to the expansion of transmission facilities, additional construction related to the CACJA and normal system expansion.

Interest Charges — Interest charges increased by $4.9 million, or 5.4 percent, for the six months ended June 30, 2012, compared with the same period in 2011, primarily due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased by $9.4 million for the six months ended June 30, 2012, compared with the same period in 2011. The increase in income tax expense was primarily due to higher pretax earnings in 2012. The effective tax rate was 36.3 percent for the first six months of 2012, compared with 37.0 percent for the same period in 2011. The higher effective tax rate for the first six months of 2011 was primarily due to tax expense from the prior year adjustments. Without this tax expense, the effective tax rate for the first six months of 2011 would have been 36.2 percent.

Factors Affecting Results of Operations

Public Utility Regulation

Resource Plan — PSCo’s 2011 electric resource plan addressed concerns that PSCo is projected to have relatively low resource needs beginning in 2017, and has proposed to fill these needs with a competitive resource acquisition process. The CPUC is expected to consider the resource plan in two phases. In the first phase, the CPUC is expected to review planning assumptions, competitive bidding structure, and determine if PSCo should acquire generation technology. The first phase is expected to be completed by the end of 2012. In the second phase, PSCo expects to conduct the competitive acquisition process, which is expected to be submitted to the CPUC for approval in 2013.

In July 2012, PSCo filed two separate applications which, if approved, would update the existing resources considered in its Resource Plan. The first is an application to purchase Brush Power, LLC and all of its assets including Brush generating Units 1, 3 and 4 for a total purchase price of approximately $75 million. Located in Brush, Colo., the generating units have a total capacity of 237 MW, including Brush Unit 1, a 60 MW combined-cycle unit; Brush Unit 3, a 30 MW simple-cycle unit; and Brush Unit 4, a 147 MW combined-cycle unit. The purchase is subject to various regulatory approvals including that of the CPUC. The Brush units currently provide energy and capacity to PSCo under purchased power agreements that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4. The transaction, if approved, is expected to result in savings to wholesale and retail customers.

The second application seeks approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013. This would be an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas purchased power agreement with an existing generator. A decision on both applications is expected between December 2012 and March 2013.

PSCo Renewable Energy Standard (RES) Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard. PSCo has filed the 2012 and 2013 RES compliance plan. PSCo proposed to acquire up to 30 MW of customer-sited solar projects each year and up to 6 MW of community scale solar projects. In March 2012, the administrative law judge (ALJ) issued a recommended decision largely approving PSCo’s proposed levels of acquisition which was affirmed by the CPUC in June 2012. PSCo has sought reconsideration of the order regarding the limit on the amounts that can be advanced to the RESA each year to cover the incremental costs of renewable energy. The CPUC also approved moving solely to a pay-for-performance basis under the Solar*Rewards distributed solar generation program, which PSCo implemented in June 2012.

CACJA — The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx from the coal-fired generation identified in the plan by at least 70 to 80 percent or greater from 2008 levels by 2017. The plan allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by 2017. The total investment associated with the adopted plan is approximately $1.0 billion through 2017 and the rate impact is expected to increase future bills on average by 2 percent annually.

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PSCo’s plan as of June 30, 2012 is as follows:

Shutdown Cherokee Units 2 and 1 in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) by the end of 2016,

after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

Shutdown Arapahoe Unit 3 (45 MW) and Unit 4 (111 MW) in 2013;

Shutdown Valmont Unit 5 (186 MW) in 2017;

Install SCR for controlling NOx and a scrubber for controlling SO2 on Pawnee Generating Station in 2014;

Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

Convert Cherokee Unit 2 to a synchronous condenser to support the transmission system in 2012.

PSCo has received certificates of public convenience and necessity (CPCN) for the conversion of Cherokee Unit 2 to a synchronous condenser, for the decommissioning of Cherokee Unit 1 and Unit 2, for the Pawnee emissions controls, and for the new natural gas combined-cycle unit at Cherokee Station. The ALJ recommended granting the CPCN for the Hayden emissions controls in June 2012 and one party has sought exceptions to that order.

Separately, in July 2012, PSCo sought approval to modify the original plan to retire Arapahoe Units 3 and 4. Subsequent transmission studies have determined that the synchronous condenser on Arapahoe Unit 3 is not needed for transmission system reliability given other upgrades to the system. PSCo has also found that a purchased power agreement with an existing generator is more cost effective than operating Arapahoe Unit 4 on natural gas. Decisions on both applications are expected by the end of the first quarter of 2013.

PSCo SmartGridCity™ (SGC) Cost Recovery — As part of its 2010 electric rate case, PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC. In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs.

In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC and also provided the additional information requested. In June 2012, the City of Boulder and the Colorado Office of Consumer Counsel filed testimony and recommend the CPUC deny PSCo’s request for recovery of the remaining portion of the SGC investment. A decision is expected in the third quarter of 2012.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of PSCo, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2011. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In July 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development. PSCo may be impacted by the provisions of Order 1000 that impact an incumbent’s right to build transmission because Colorado does not have legislation protecting the rights of utilities to develop transmission projects in their service areas. Compliance filings to address these new requirements are due October 2012, and are effective prospectively.

In May 2012, the FERC issued Order 1000-A, its order on rehearing of Order 1000. Order 1000-A declined all motions for rehearing and offered limited clarification of aspects of the final rule. Several parties filed requests for clarification of Order 1000-A. Several appeals of Order 1000 have also been filed and these appeals have been consolidated into the U.S. Court of Appeals for the District of Columbia Circuit. These appeals are expected to be heard over the next 12 months with a ruling expected sometime in mid-2013.

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Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of June 30, 2012, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against PSCo. PSCo has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

PSCo’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2011, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

Item 6 — EXHIBITS

* Indicates incorporation by reference

Furnished, herewith, not filed. Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

3.01*		Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*		By-Laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
31.01		Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02		Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.
101 t		The following materials from PSCo’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Public Service Company of Colorado
Aug. 6, 2012
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller

		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

Colorado		84-0296600
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1800 Larimer, Suite 1100
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(Do not check if smaller reporting company)

Class		Outstanding at Aug. 6, 2012
Common Stock, $0.01 par value		100 shares

	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011
Operating revenues
Electric	$	714,651		$	749,791		$	1,396,930		$	1,453,944
Natural gas		147,398			174,730			530,402			602,921
Steam and other		7,452			8,579			18,221			20,682
Total operating revenues		869,501			933,100			1,945,553			2,077,547

Operating expenses
Electric fuel and purchased power		294,698			352,216			605,597			676,013
Cost of natural gas sold and transported		57,091			94,022			313,968			398,960
Cost of sales — steam and other		2,928			3,989			7,095			9,110
Operating and maintenance expenses		180,100			186,668			348,482			357,339
Demand side management program expenses		29,348			27,767			58,792			58,089
Depreciation and amortization		80,151			80,277			163,740			160,246
Taxes (other than income taxes)		32,875			34,985			66,663			69,306
Total operating expenses		677,191			779,924			1,564,337			1,729,063

Operating income		192,310			153,176			381,216			348,484

Other income, net		1,550			2,235			2,582			3,898
Allowance for funds used during construction — equity		3,548			1,798			6,274			3,417

Interest charges and financing costs
Interest charges — includes other financing costs of $1,790, $1,760, $3,580 and $3,276, respectively		48,074			46,036			96,365			91,435
Allowance for funds used during construction — debt		(1,534	)		(820	)		(2,695	)		(1,546	)
Total interest charges and financing costs		46,540			45,216			93,670			89,889

Income before income taxes		150,868			111,993			296,402			265,910
Income taxes		55,461			40,975			107,710			98,262
Net income	$	95,407		$	71,018		$	188,692		$	167,648

PART I — FINANCIAL INFORMATION

Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 4 —	Controls and Procedures	26

PART II — OTHER INFORMATION

Item 1 —	Legal Proceedings	26
Item 1A —	Risk Factors	26
Item 4 —	Mine Safety Disclosures	26
Item 5 —	Other Information	26
Item 6 —	Exhibits	26

SIGNATURES		27

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1