UNITED STATES Commission File Number 6226 West Sahara Avenue Las Vegas, Nevada 89146 Nevada Power Company are held by its parent company, NV Energy, Inc., which is AFUDC Allowance for United States Environmental Protection Agency Federal Energy Regulatory Commission Public Utilities Commission of Nevada OPERATIONS (Unaudited) millions) Three Months Ended March 31, 2013 2012 OPERATING REVENUES $ 584,222 $ 611,420 OPERATING EXPENSES: Fuel for power generation 147,248 117,035 Purchased power 121,310 117,116 Gas purchased for resale 37,620 31,617 Deferred energy (79,065) (11,739) Energy efficiency program costs 9,845 19,425 Other operating expenses 104,672 103,601 Maintenance 24,906 32,526 Depreciation and amortization 96,002 90,862 Taxes other than income 16,476 14,509 Total Operating Expenses 479,014 514,952 OPERATING INCOME 105,208 96,468 OTHER INCOME (EXPENSE): Interest expense (net of AFUDC-debt: $2,131 and $1,595) (73,337) (77,931) Interest expense on regulatory items (827) (2,202) AFUDC-equity 2,889 1,932 Other income 3,820 4,194 Other expense (4,251) (3,060) Total Other Income (Expense) (71,706) (77,067) Income Before Income Tax Expense 33,502 19,401 Income tax expense 12,027 7,228 NET INCOME 21,475 12,173 Other comprehensive income (loss): Change in compensation retirement benefits liability and amortization (Net of taxes $(136) and $(89) in 2013 and 2012, respectively) 246 155 Change in market value of risk management assets and liabilities (Net of taxes $(110) and $141 in 2013 and 2012, respectively) 199 (246) OTHER COMPREHENSIVE INCOME (LOSS) 445 (91) COMPREHENSIVE INCOME $ 21,920 $ 12,082 Amount per share basic and diluted (Note 8) Net income per share - basic and diluted $ 0.09 $ 0.05 Weighted Average Shares of Common Stock Outstanding - basic 235,193,702 235,999,750 Weighted Average Shares of Common Stock Outstanding - diluted 237,005,888 237,526,863 Dividends Declared Per Share of Common Stock $ 0.19 $ 0.13 The accompanying notes are an integral part of the financial statements. STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited) March 31, December 31, 2013 2012 ASSETS Current Assets: Cash and cash equivalents $ 250,953 $ 298,271 Accounts receivable less allowance for uncollectible accounts: 2013 - $6,533; 2012 - $8,748 317,191 373,099 Materials, supplies and fuel, at average cost 133,613 138,337 Deferred income taxes 88,648 60,592 Other current assets 54,397 40,750 Total Current Assets 844,802 911,049 Utility Property: Plant in service 12,077,001 12,031,053 Construction work-in-progress 730,262 708,109 Total 12,807,263 12,739,162 Less accumulated provision for depreciation 3,378,468 3,313,188 Total Utility Property, Net 9,428,795 9,425,974 Investments and other property, net 58,389 56,660 Deferred Charges and Other Assets: Deferred energy (Note 3) 84,120 87,072 Regulatory assets 1,102,348 1,132,768 Regulatory asset for pension plans 277,836 281,195 Other deferred charges and assets 82,343 89,418 Total Deferred Charges and Other Assets 1,546,647 1,590,453 TOTAL ASSETS $ 11,878,633 $ 11,984,136 (Continued) NV ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands, Except Share Amounts) (Unaudited) March 31, December 31, LIABILITIES AND SHAREHOLDERS' EQUITY 2013 2012 Current Liabilities: Current maturities of long-term debt (Note 4) $ 481,342 $ 356,283 Accounts payable 280,206 332,245 Accrued expenses 95,080 127,693 Deferred energy (Note 3) 56,336 136,865 Other current liabilities 69,306 66,221 Total Current Liabilities 982,270 1,019,307 Long-term debt (Note 4) 4,541,241 4,669,798 Commitments and Contingencies (Note 7) Deferred Credits and Other Liabilities: Deferred income taxes 1,510,369 1,470,973 Deferred investment tax credit 12,984 13,538 Accrued retirement benefits 164,315 162,260 Regulatory liabilities 558,692 550,687 Other deferred credits and liabilities 564,911 540,202 Total Deferred Credits and Other Liabilities 2,811,271 2,737,660 Shareholders' Equity: Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued for 2013 and 2012; 235,526,514 and 235,079,156 outstanding for 2013 and 2012, respectively 236,000 236,000 Treasury stock at cost, 473,236 shares and 920,594 shares for 2013 and 2012, respectively (8,660) (16,804) Other paid-in capital 2,714,107 2,712,943 Retained earnings 612,030 635,303 Accumulated other comprehensive loss (9,626) (10,071) Total Shareholders' Equity 3,543,851 3,557,371 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 11,878,633 $ 11,984,136 The accompanying notes are an integral part of the financial statements. (Concluded) millions) For the Three Months Ended, March 31, 2013 2012 CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: Net Income $ 21,475 $ 12,173 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 96,002 90,862 Deferred taxes and deferred investment tax credit 11,956 (5,183) AFUDC-equity (2,889) (1,932) Deferred energy (77,578) (9,134) Amortization of other regulatory assets 41,621 39,028 Deferred rate increase 2,103 2,691 Other, net (897) 1,575 Changes in certain assets and liabilities: Accounts receivable 68,131 31,208 Materials, supplies and fuel 4,815 (874) Other current assets (13,648) (13,021) Accounts payable (29,795) (37,825) Accrued retirement benefits 2,055 2,221 Other current liabilities (29,335) (29,348) Other deferred assets (1,263) (1,602) Other regulatory assets (2,379) 4,164 Other deferred liabilities (1,480) (17,687) Net Cash from Operating Activities 88,894 67,316 CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: Additions to utility plant (excluding AFUDC-equity) (97,948) (115,817) Customer advances for construction (629) (184) Contributions in aid of construction 13,570 26,052 Investments and other property - net 111 48 Net Cash used by Investing Activities (84,896) (89,901) CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: Proceeds from issuance of long-term debt, net of costs - 10,951 Retirement of long-term debt (3,671) (3,295) Sale of common stock 754 - Common stock repurchased (3,651) - Dividends paid (44,748) (30,680) Net Cash used by Financing Activities (51,316) (23,024) Net Decrease in Cash and Cash Equivalents (47,318) (45,609) Beginning Balance in Cash and Cash Equivalents 298,271 145,944 Ending Balance in Cash and Cash Equivalents $ 250,953 $ 100,335 Supplemental Disclosures of Cash Flow Information: Cash paid during period for: Interest $ 88,337 $ 88,606 Income taxes $ 2 $ - Significant non-cash transactions: Accrued construction expenses as of March 31, $ 61,262 $ 85,850 Issuance of treasury stock $ 11,041 $ - The accompanying notes are an integral part of the financial statements. Accumulated Common Common Treasury Treasury Other Other Total Stock Stock Stock Stock Paid-in Retained Comprehensive Shareholders' Shares Amount Shares Amount Capital Earnings Income (Loss) Equity December 31, 2011 235,999,750 $ 236,000 - $ - $ 2,713,736 $ 464,277 $ (7,934) $ 3,406,079 Net Income - - - - - 12,173 - 12,173 Change in compensation retirement benefits liability and amortization (net of taxes $(89)) - - - - - - 155 155 Change in market value of risk management assets and liabilities (net of taxes $ 141) - - - - - - (246) (246) Dividends Declared - - - - - (30,680) - (30,680) March 31, 2012 235,999,750 $ 236,000 - $ - $ 2,713,736 $ 445,770 $ (8,025) $ 3,387,481 December 31, 2012 235,999,750 $ 236,000 (920,594) $ (16,804) $ 2,712,943 $ 635,303 �� $ (10,071) $ 3,557,371 Net Income - - - - - 21,475 - 21,475 Employee Benefits - - 644,536 11,795 1,164 - - 12,959 Change in compensation retirement benefits liability and amortization (net of taxes $(136)) - - - - - - 246 246 Change in market value of risk management assets and liabilities (net of taxes $(110)) - - - - - - 199 199 Common stock repurchased - - (197,178) (3,651) - - - (3,651) Dividends Declared - - - - - (44,748) - (44,748) March 31, 2013 235,999,750 $ 236,000 (473,236) $ (8,660) $ 2,714,107 $ 612,030 $ (9,626) $ 3,543,851 The accompanying notes are an integral part of the financial statements. NEVADA POWER COMPANY Three Months Ended March 31, 2013 2012 OPERATING REVENUES $ 371,863 $ 395,688 OPERATING EXPENSES: Fuel for power generation 105,531 80,549 Purchased power 81,408 81,531 Deferred energy (45,355) 2,171 Energy efficiency program costs 7,967 15,774 Other operating expenses 67,392 66,462 Maintenance 18,075 23,073 Depreciation and amortization 68,661 64,990 Taxes other than income 9,959 8,454 Total Operating Expenses 313,638 343,004 OPERATING INCOME 58,225 52,684 OTHER INCOME (EXPENSE): Interest expense (net of AFUDC-debt: $1,837 and $1,179) (51,259) (54,405) Interest income (expense) on regulatory items (802) (2,016) AFUDC-equity 2,366 1,413 Other income 2,404 1,709 Other expense (2,401) (1,346) Total Other Income (Expense) (49,692) (54,645) Income (Loss) Before Income Tax Expense 8,533 (1,961) Income tax expense 3,088 (645) NET INCOME (LOSS) 5,445 (1,316) Other comprehensive income: Change in compensation retirement benefits liability and amortization (Net of taxes $(54) and $(32) in 2013 and 2012, respectively) 97 63 COMPREHENSIVE INCOME (LOSS) $ 5,542 $ (1,253) The accompanying notes are an integral part of the financial statements. March 31, December 31, 2013 2012 ASSETS Current Assets: Cash and cash equivalents $ 132,216 $ 201,202 Accounts receivable less allowance for uncollectible accounts: 2013 - $5,580; 2012 - $7,622 198,740 248,501 Materials, supplies and fuel, at average cost 80,998 77,675 Deferred income taxes 80,265 48,590 Other current assets 38,008 28,763 Total Current Assets 530,227 604,731 Utility Property: Plant in service 8,399,239 8,363,566 Construction work-in-progress 603,495 567,941 Total 9,002,734 8,931,507 Less accumulated provision for depreciation 2,091,598 2,035,322 Total Utility Property, Net 6,911,136 6,896,185 Investments and other property, net 51,201 49,808 Deferred Charges and Other Assets: Deferred energy (Note 3) 84,120 87,072 Regulatory assets 781,916 804,013 Regulatory asset for pension plans 135,191 136,682 Other deferred charges and assets 64,924 62,654 Total Deferred Charges and Other Assets 1,066,151 1,090,421 TOTAL ASSETS $ 8,558,715 $ 8,641,145 (Continued) NEVADA POWER COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands, Except Share Amounts) (Unaudited) March 31, December 31, 2013 2012 LIABILITIES AND SHAREHOLDER'S EQUITY Current Liabilities: Current maturities of long-term debt (Note 4) $ 231,075 $ 106,048 Accounts payable 168,582 201,193 Accounts payable, affiliated companies 39,650 42,036 Accrued expenses 58,774 86,433 Deferred energy (Note 3) 38,915 86,102 Other current liabilities 54,935 52,567 Total Current Liabilities 591,931 574,379 Long-term debt (Note 4) 3,102,390 3,230,808 Commitments and Contingencies (Note 7) Deferred Credits and Other Liabilities: Deferred income taxes 1,136,115 1,101,804 Deferred investment tax credit 4,407 4,688 Accrued retirement benefits 50,328 49,381 Regulatory liabilities 329,806 323,400 Other deferred credits and liabilities 465,878 434,367 Total Deferred Credits and Other Liabilities 1,986,534 1,913,640 Shareholder's Equity: Common stock, $1.00 par value; 1,000 shares authorized issued and outstanding for 2013 and 2012 1 1 Other paid-in capital 2,308,211 2,308,211 Retained earnings 574,057 618,612 Accumulated other comprehensive loss (4,409) (4,506) Total Shareholder's Equity 2,877,860 2,922,318 TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $ 8,558,715 $ 8,641,145 The accompanying notes are an integral part of the financial statements. (Concluded) For the Three Months Ended, March 31, 2013 2012 CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: Net Income (Loss) $ 5,445 $ (1,316) Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 68,661 64,990 Deferred taxes and deferred investment tax credit 2,949 (6,349) AFUDC-equity (2,366) (1,413) Deferred energy (44,235) 4,050 Amortization of other regulatory assets 22,119 18,301 Deferred rate increase 2,103 2,691 Other, net (4,261) (796) Changes in certain assets and liabilities: Accounts receivable 50,792 22,441 Materials, supplies and fuel (3,232) (2,209) Other current assets (9,246) (8,674) Accounts payable (24,421) (14,248) Accrued retirement benefits 947 1,572 Other current liabilities (25,097) (27,419) Other deferred assets (491) (1,288) Other regulatory assets (801) 9,880 Other deferred liabilities (1,348) (7,495) Net Cash from Operating Activities 37,518 52,718 CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: Additions to utility plant (excluding AFUDC-equity) (59,357) (66,843) Customer advances for construction (749) 654 Contributions in aid of construction 6,890 15,951 Investments and other property - net 103 40 Net Cash used by Investing Activities (53,113) (50,198) CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: Proceeds from issuance of long-term debt, net of costs - 12,432 Retirement of long-term debt (3,391) (3,129) Dividends paid (50,000) (39,000) Net Cash used by Financing Activities (53,391) (29,697) Net Decrease in Cash and Cash Equivalents (68,986) (27,177) Beginning Balance in Cash and Cash Equivalents 201,202 65,887 Ending Balance in Cash and Cash Equivalents $ 132,216 $ 38,710 Supplemental Disclosures of Cash Flow Information: Cash paid during period for: Interest $ 71,187 $ 71,276 Income taxes $ 1 $ - Significant non-cash transactions: Accrued construction expenses as of March 31, $ 48,812 $ 72,179 The accompanying notes are an integral part of the financial statements. Accumulated Common Common Other Other Total Stock Stock Paid-in Retained Comprehensive Shareholder's Shares Amount Capital Earnings Income (Loss) Equity December 31, 2011 1,000 $ 1 $ 2,308,219 $ 544,874 $ (4,117) $ 2,848,977 Net Loss - - - (1,316) - (1,316) Change in compensation retirement benefits liability and amortization (net of taxes $(32)) - - - - 63 63 Dividends Declared - - - (39,000) - (39,000) March 31, 2012 1,000 $ 1 $ 2,308,219 $ 504,558 $ (4,054) $ 2,808,724 December 31, 2012 1,000 $ 1 $ 2,308,211 $ 618,612 $ (4,506) $ 2,922,318 Net Income - - - 5,445 - 5,445 Change in compensation retirement benefits liability and amortization (net of taxes $(54)) - - - - 97 97 Dividends Declared - - - (50,000) - (50,000) March 31, 2013 1,000 $ 1 $ 2,308,211 $ 574,057 $ (4,409) $ 2,877,860 The accompanying notes are an integral part of the financial statements. Three Months Ended March 31, 2013 2012 OPERATING REVENUES: Electric $ 172,627 $ 169,806 Gas 39,729 45,922 Total Operating Revenues 212,356 215,728 OPERATING EXPENSES: Fuel for power generation 41,717 36,486 Purchased power 39,902 35,585 Gas purchased for resale 37,620 31,617 Deferral of energy - electric - net (19,335) (12,670) Deferral of energy - gas - net (14,375) (1,240) Energy efficiency program costs 1,878 3,651 Other operating expenses 35,805 36,432 Maintenance 6,831 9,453 Depreciation and amortization 27,341 25,872 Taxes other than income 6,295 5,863 Total Operating Expenses 163,679 171,049 OPERATING INCOME 48,677 44,679 OTHER INCOME (EXPENSE): Interest expense (net of AFUDC-debt: $294 and $416) (15,525) (16,973) Interest expense on regulatory items (25) (186) AFUDC-equity 523 519 Other income 1,140 2,183 Other expense (1,248) (1,335) Total Other Income (Expense) (15,135) (15,792) Income Before Income Tax Expense 33,542 28,887 Income tax expense 11,638 10,243 NET INCOME 21,904 18,644 Other comprehensive income: Change in compensation retirement benefits liability and amortization (Net of taxes $(31) and $(23) in 2013 and 2012, respectively) 59 42 COMPREHENSIVE INCOME $ 21,963 $ 18,686 The accompanying notes are an integral part of the financial statements. March 31, December 31, 2013 2012 ASSETS Current Assets: Cash and cash equivalents $ 85,280 $ 60,786 Accounts receivable less allowance for uncollectible accounts: 2013 - $953; 2012 - $1,126 118,326 124,464 Materials, supplies and fuel, at average cost 52,615 60,662 Intercompany income taxes receivable 10,351 10,351 Deferred income taxes 18,770 21,589 Other current assets 16,268 11,633 Total Current Assets 301,610 289,485 Utility Property: Plant in service 3,677,762 3,667,487 Construction work-in-progress 126,767 140,168 Total 3,804,529 3,807,655 Less accumulated provision for depreciation 1,286,870 1,277,866 Total Utility Property, Net 2,517,659 2,529,789 Investments and other property, net 6,836 6,499 Deferred Charges and Other Assets: Regulatory assets 320,432 328,755 Regulatory asset for pension plans 138,843 140,268 Other deferred charges and assets 11,811 21,477 Total Deferred Charges and Other Assets 471,086 490,500 TOTAL ASSETS $ 3,297,191 $ 3,316,273 (Continued) SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands, Except Share Amounts) (Unaudited) March 31, December 31, 2013 2012 LIABILITIES AND SHAREHOLDER'S EQUITY Current Liabilities: Current maturities of long-term debt (Note 4) $ 250,267 $ 250,235 Accounts payable 90,697 106,415 Accounts payable, affiliated companies 22,387 21,534 Accrued expenses 26,464 32,936 Deferred energy (Note 3) 17,421 50,763 Other current liabilities 14,368 13,655 Total Current Liabilities 421,604 475,538 Long-term debt (Note 4) 928,851 928,990 Commitments and Contingencies (Note 7) Deferred Credits and Other Liabilities: Deferred income taxes 473,937 465,508 Deferred investment tax credit 8,577 8,850 Accrued retirement benefits 98,956 98,676 Regulatory liabilities 228,886 227,287 Other deferred credits and liabilities 75,681 72,688 Total Deferred Credits and Other Liabilities 886,037 873,009 Shareholder's Equity: Common stock, $3.75 par value; 20,000,000 shares authorized 1,000 shares issued and outstanding for 2013 and 2012 4 4 Other paid-in capital 1,111,266 1,111,266 Retained deficit (49,082) (70,986) Accumulated other comprehensive loss (1,489) (1,548) Total Shareholder's Equity 1,060,699 1,038,736 TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $ 3,297,191 $ 3,316,273 The accompanying notes are an integral part of the financial statements. (Concluded) For the Three Months Ended, March 31, 2013 2012 CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: Net Income $ 21,904 $ 18,644 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 27,341 25,872 Deferred taxes and deferred investment tax credit 11,707 3,537 AFUDC-equity (523) (519) Deferred energy (33,343) (13,184) Amortization of other regulatory assets 19,441 20,668 Other, net 2,099 2,249 Changes in certain assets and liabilities: Accounts receivable 17,331 8,869 Materials, supplies and fuel 8,047 1,335 Other current assets (4,635) (4,564) Accounts payable (3,198) (17,675) Accrued retirement benefits 280 367 Other current liabilities (5,757) (5,388) Other deferred assets (772) (314) Other regulatory assets (1,578) (5,716) Other deferred liabilities (1,787) (4,214) Net Cash from Operating Activities 56,557 29,967 CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: Additions to utility plant (excluding AFUDC-equity) (38,591) (48,974) Customer advances for construction 120 (838) Contributions in aid of construction 6,680 10,101 Investments and other property - net 8 8 Net Cash used by Investing Activities (31,783) (39,703) CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: Proceeds from issuance of long-term debt, net of costs - (1,441) Retirement of long-term debt (280) (166) Dividends paid - (20,000) Net Cash used by Financing Activities (280) (21,607) Net Increase (Decrease) in Cash and Cash Equivalents 24,494 (31,343) Beginning Balance in Cash and Cash Equivalents 60,786 55,195 Ending Balance in Cash and Cash Equivalents $ 85,280 $ 23,852 Supplemental Disclosures of Cash Flow Information: Cash paid during period for: Interest $ 15,780 $ 15,944 Significant non-cash transactions: Accrued construction expenses as of March 31, $ 12,450 $ 13,671 The accompanying notes are an integral part of the financial statements. Accumulated Common Common Other Other Total Stock Stock Paid-In Retained Comprehensive Shareholder's Shares Amount Capital Deficit Income (Loss) Equity December 31, 2011 1,000 $ 4 $ 1,111,262 $ (135,340) $ (1,384) $ 974,542 Net Income - - - 18,644 - 18,644 Change in compensation retirement benefits liability and amortization (net of taxes $(23)) - - - - 42 42 Dividends Declared - - - (20,000) - (20,000) March 31, 2012 1,000 $ 4 $ 1,111,262 $ (136,696) $ (1,342) $ 973,228 December 31, 2012 1,000 $ 4 $ 1,111,266 $ (70,986) $ (1,548) $ 1,038,736 Net Income - - - 21,904 - 21,904 Change in compensation retirement benefits liability and amortization (net of taxes $(31)) - - - - 59 59 March 31, 2013 1,000 $ 4 $ 1,111,266 $ (49,082) $ (1,489) $ 1,060,699 The accompanying notes are an integral part of the financial statements. accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the Consolidated Financial Statements as of March 31, 2014 and for the three-month periods ended March 31, 2014 and 2013. Certain amounts in the prior period Consolidated Statement of Operations have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported net income. The results of operations for the three-month period ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year. 2014. Three Months Ended March 31, 2013 NVE Consolidated NVE Other NPC Electric SPPC Total SPPC Electric SPPC Gas Operating Revenues $ 584,222 $ 3 $ 371,863 $ 212,356 $ 172,627 $ 39,729 Energy Costs: Fuel for power generation 147,248 - 105,531 41,717 41,717 - Purchased power 121,310 - 81,408 39,902 39,902 - Gas purchased for resale 37,620 - - 37,620 - 37,620 Deferred energy (79,065) - (45,355) (33,710) (19,335) (14,375) Energy efficiency program costs 9,845 - 7,967 1,878 1,878 - Total Costs $ 236,958 $ - $ 149,551 $ 87,407 $ 64,162 $ 23,245 Gross Margin $ 347,264 $ 3 $ 222,312 $ 124,949 $ 108,465 $ 16,484 Other operating expenses 104,672 1,475 67,392 35,805 Maintenance 24,906 - 18,075 6,831 Depreciation and amortization 96,002 - 68,661 27,341 Taxes other than income 16,476 222 9,959 6,295 Operating Income (Loss) $ 105,208 $ (1,694) $ 58,225 $ 48,677 Three Months Ended March 31, 2012 NVE Consolidated NVE Other NPC Electric SPPC Total SPPC Electric SPPC Gas Operating Revenues $ 611,420 $ 4 $ 395,688 $ 215,728 $ 169,806 $ 45,922 Energy Costs: Fuel for power generation 117,035 - 80,549 36,486 36,486 - Purchased power 117,116 - 81,531 35,585 35,585 - Gas purchased for resale 31,617 - 31,617 - 31,617 Deferred energy (11,739) - 2,171 (13,910) (12,670) (1,240) Energy efficiency program costs 19,425 - 15,774 3,651 3,651 - Total Costs $ 273,454 $ - $ 180,025 $ 93,429 $ 63,052 $ 30,377 Gross Margin $ 337,966 $ 4 $ 215,663 $ 122,299 $ 106,754 $ 15,545 Other operating expenses 103,601 707 66,462 36,432 Maintenance 32,526 - 23,073 9,453 Depreciation and amortization 90,862 - 64,990 25,872 Taxes other than income 14,509 192 8,454 5,863 Operating Income (Loss) $ 96,468 $ (895) $ 52,684 $ 44,679 March 31, 2013 NVE Total NPC Electric SPPC Electric SPPC Gas Deferred Energy Cumulative Balance as of December 31, 2012 $ (151,880) $ (101,117) $ (32,693) $ (18,070) 2013 Amortization 55,053 30,313 11,296 13,444 2013 Deferred Energy Under Collections (1) 25,498 16,896 7,795 807 Deferred Energy Balance at March 31, 2013 - Subtotal $ (71,329) $ (53,908) $ (13,602) $ (3,819) Reinstatement of deferred energy (effective 6/07, 10 years) 99,113 99,113 - - Total Deferred Energy $ 27,784 $ 45,205 $ (13,602) $ (3,819) Deferred Assets Deferred energy $ 84,120 $ 84,120 $ - $ - Current Liabilities Deferred energy (56,336) (38,915) (13,602) (3,819) Total Net Deferred Energy $ 27,784 $ 45,205 $ (13,602) $ (3,819) (1) These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K. Anticipated Requested Present $ Change in Effective Revenue Revenue Revenue Date Requirement Requirement Requirement Revenue Requirement Subject To Change: REPR(1) Oct. 2013 $ 28.4 $ 38.7 $ (10.3) TRED(1) Oct. 2013 15.7 15.9 (0.2) EEPR Base(1) Oct. 2013 45.9 32.6 13.3 EEPR Amortization(1) Oct. 2013 (29.9) 9.0 (38.9) EEIR Base Oct. 2013 15.1 10.6 4.5 EEIR Amortization Oct. 2013 (6.7) 10.7 (17.4) Total Revenue Requirement $ 68.5 $ 117.5 $ (49.0) (1) Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income. Anticipated Requested Present $ Change in Effective Revenue Revenue Revenue Date Requirement Requirement Requirement Revenue Requirement Subject To Change: REPR (1) Oct. 2013 $ 42.3 $ 44.4 $ (2.1) TRED (1) Oct. 2013 7.4 6.3 1.1 EEPR Base (1) Oct. 2013 6.0 5.6 0.4 EEPR Amortization (1) Oct. 2013 (2.2) 1.8 (4.0) EEIR Base Oct. 2013 5.6 4.7 0.9 EEIR Amortization Oct. 2013 1.1 1.9 (0.8) Total Revenue Requirement $ 60.2 $ 64.7 $ (4.5) (1) Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income. March 31, December 31, 2013 2012 Long-Term Debt: Stated Rate Maturity Date Consolidated NVE Holding Co. NPC SPPC Consolidated NVE Holding Co. NPC SPPC Secured Debt General and Refunding Mortgage Securities NPC Series L 5.875 % 2015 $ 250,000 $ - $ 250,000 $ - $ 250,000 $ - $ 250,000 $ - NPC Series M 5.950 % 2016 210,000 - 210,000 - 210,000 - 210,000 - NPC Series N 6.650 % 2036 370,000 - 370,000 - 370,000 - 370,000 - NPC Series O 6.500 % 2018 325,000 - 325,000 - 325,000 - 325,000 - NPC Series R 6.750 % 2037 350,000 - 350,000 - 350,000 - 350,000 - NPC Series S 6.500 % 2018 500,000 - 500,000 - 500,000 - 500,000 - NPC Series U 7.375 % 2014 125,000 - 125,000 - 125,000 - 125,000 - NPC Series V 7.125 % 2019 500,000 - 500,000 - 500,000 - 500,000 - NPC Series X 5.375 % 2040 250,000 - 250,000 - 250,000 - 250,000 - NPC Series Y 5.450 % 2041 250,000 - 250,000 - 250,000 - 250,000 - SPPC Series M 6.000 % 2016 450,000 - - 450,000 450,000 - - 450,000 SPPC Series P 6.750 % 2037 251,742 - - 251,742 251,742 - - 251,742 SPPC Series Q 5.450 % 2013 250,000 - - 250,000 250,000 - - 250,000 Variable Rate Debt (Secured by General and Refunding Mortgage Securities) NPC IDRB Series 2000A 2020 98,100 - 98,100 - 98,100 - 98,100 - NPC PCRB Series 2006 2036 37,700 - 37,700 - 37,700 - 37,700 - NPC PCRB Series 2006A 2032 37,975 - 37,975 - 37,975 - 37,975 - SPPC PCRB Series 2006A 2031 58,200 - - 58,200 58,200 - - 58,200 SPPC PCRB Series 2006B 2036 75,000 - - 75,000 75,000 - - 75,000 SPPC PCRB Series 2006C 2036 81,475 - - 81,475 81,475 - - 81,475 Senior Notes NVE Senior Notes 6.250 % 2020 315,000 315,000 - - 315,000 315,000 - - NVE Term Loan 2.810 % 2014 195,000 195,000 - - 195,000 195,000 - - Obligations under capital leases 40,872 - 39,268 1,604 44,258 - 42,908 1,350 Unamortized bond premium and discount, net 1,519 - (9,578) 11,097 1,631 - (9,827) 11,458 Current maturities (481,342) - (231,075) (250,267) (356,283) - (106,048) (250,235) Total Long-Term Debt $ 4,541,241 $ 510,000 $ 3,102,390 $ 928,851 $ 4,669,798 $ 510,000 $ 3,230,808 $ 928,990 NVE Pension Benefits Other Postretirement Benefits For the Three Months Ended March 31, For the Three Months Ended March 31, 2013 2012 2013 2012 Service cost $ 5,132 $ 4,406 $ 660 $ 595 Interest cost 9,303 10,228 1,677 1,905 Expected return on plan assets (12,708) (12,447) (1,687) (1,563) Amortization of prior service cost (720) (724) (952) (987) Amortization of net loss 4,797 3,473 890 731 Net periodic benefit cost $ 5,804 $ 4,936 $ 588 $ 681 The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 33.8% and 33.2%, respectively. NPC Pension Benefits Other Postretirement Benefits For the Three Months Ended March 31, For the Three Months Ended March 31, 2013 2012 2013 2012 Service cost $ 2,761 $ 2,358 $ 389 $ 350 Interest cost 4,453 4,881 556 602 Expected return on plan assets (6,270) (6,237) (631) (592) Amortization of prior service cost (453) (456) (23) 229 Amortization of net loss 2,117 1,363 289 221 Net periodic benefit cost $ 2,608 $ 1,909 $ 580 $ 810 The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.1% and 35.6%, respectively. SPPC Pension Benefits Other Postretirement Benefits For the Three Months Ended March 31, For the Three Months Ended March 31, 2013 2012 2013 2012 Service cost $ 1,926 $ 1,695 $ 251 $ 227 Interest cost 4,558 5,043 1,104 1,283 Expected return on plan assets (6,162) (5,937) (1,022) (941) Amortization of prior service cost (277) (277) (933) (1,220) Amortization of net loss 2,501 2,026 592 504 Net periodic benefit cost $ 2,546 $ 2,550 $ (8) $ (147) The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 34.4% and 33.0%, respectively. Reid Gardner Generating Station Three Months Ended March 31, 2013 2012 Basic EPS Numerator ($000) Net Income $ 21,475 $ 12,173 Denominator Weighted average number of common shares outstanding 235,193,702 235,999,750 Per Share Amounts Net Income per share - basic $ 0.09 $ 0.05 Diluted EPS Numerator ($000) Net Income $ 21,475 $ 12,173 Denominator(1) Weighted average number of shares outstanding before dilution 235,193,702 235,999,750 Stock options 18,767 35,283 Non-Employee Director stock plan 179,971 153,686 Employee stock purchase plan 10,539 10,888 Restricted Shares 579,000 497,750 Performance Shares 1,023,909 829,506 Diluted Weighted Average Number of Shares 237,005,888 237,526,863 Per Share Amounts Net income per share - diluted $ 0.09 $ 0.05 (1) The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the prior period. If the conditions for conversion were met under this plan, 0 and 333,140 shares would be included for the three months ended March 31, 2013 and 2012, respectively. were $33 million and $37 million, respectively. The Available Liquidity as of March 31, 2013 (in millions) NVE NPC SPPC Cash and Cash Equivalents $ 27.4 $ 132.2 $ 85.3 Balance available on Revolving Credit Facilities(1) N/A 497.3 243.7 27.4 629.5 329.0 (1) As of May 7, 2013, NPC and SPPC had approximately $497.3 million and $243.7 million available under their revolving credit facilities, which includes reductions in availability for letters of credit. In addition, certain financing agreements Three Months Ended March 31, 2013 2012 Variance % Change Operating Revenues: $ 371,863 $ 395,688 $ (23,825) (6.0) % Energy Costs: Fuel for power generation 105,531 80,549 24,982 31.0 % Purchased power 81,408 81,531 (123) (0.2) % Deferred energy (45,355) 2,171 (47,526) (2,189.1) % Energy efficiency program costs 7,967 15,774 (7,807) (49.5) % Total Costs $ 149,551 $ 180,025 $ (30,474) (16.9) % Gross Margin $ 222,312 $ 215,663 $ 6,649 3.1 % Three Months Ended March 31, 2013 2012 Variance % Change NPC Heating 1,050 924 126 13.6 % Cooling 86 41 45 109.8 % Operating Revenue Three Months Ended March 31, Operating Revenues: 2013 2012 Variance % Change Residential $ 191,894 $ 194,489 $ (2,595) (1.3) % Commercial 79,561 87,735 (8,174) (9.3) % Industrial 88,477 99,914 (11,437) (11.4) % Retail revenues 359,932 382,138 (22,206) (5.8) % Other 11,931 13,550 (1,619) (11.9) % Total Operating Revenues $ 371,863 $ 395,688 $ (23,825) (6.0) % Retail sales in thousands of MWhs Residential 1,611 1,536 75 4.9 % Commercial 916 957 (41) (4.3) % Industrial 1,635 1,652 (17) (1.0) % Retail sales in thousands of MWhs 4,162 4,145 17 0.4 % Average retail revenue per MWh $ 86.48 $ 92.19 (5.71) (6.2) % Three Months Ended March 31, 2013 2012 Variance % Change Energy Costs Fuel for power generation $ 105,531 $ 80,549 $ 24,982 31.0 % Purchased power 81,408 81,531 (123) (0.2) % Total Energy Costs $ 186,939 $ 162,080 $ 24,859 15.3 % MWhs MWhs Generated (in thousands) 3,675 3,287 388 11.8 % Purchased Power (in thousands) 643 1,026 (383) (37.3) % Total MWhs 4,318 4,313 5 0.1 % Average cost per MWh Average fuel cost per MWh of Generated Power $ 28.72 $ 24.51 $ 4.21 17.2 % Average cost per MWh of Purchased Power $ 126.61 $ 79.46 $ 47.14 59.3 % Average total cost per MWh $ 43.29 $ 37.58 $ 5.71 15.2 % Deferred Energy Three Months Ended March 31, 2013 2012 Variance % Change Deferred energy $ (45,355) $ 2,171 $ (47,526) (2,189.1) % Other Operating Expenses Three Months Ended March 31, 2013 2012 Variance % Change Energy efficiency program costs $ 7,967 $ 15,774 $ (7,807) (49.5) % Other operating expenses $ 67,392 $ 66,462 $ 930 1.4 % Maintenance $ 18,075 $ 23,073 $ (4,998) (21.7) % Depreciation and amortization $ 68,661 $ 64,990 $ 3,671 5.6 % Interest Expense Three Months Ended March 31, 2013 2012 Variance % Change Interest expense (net of AFUDC-debt: $1,837 and $1,179) $ 51,259 $ 54,405 $ (3,146) (5.8) % Other Income (Expense) Three Months Ended March 31, 2013 2012 Variance % Change Interest income (expense) on regulatory items $ (802) $ (2,016) $ 1,214 (60.2) % AFUDC-equity $ 2,366 $ 1,413 $ 953 67.4 % Other income $ 2,404 $ 1,709 $ 695 40.7 % Other expense $ (2,401) $ (1,346) $ (1,055) 78.4 % Three Months Ended March 31, 2013 2012 Variance % Change Operating Revenues: Electric $ 172,627 $ 169,806 $ 2,821 1.7 % Gas 39,729 45,922 (6,193) (13.5) % $ 212,356 $ 215,728 $ (3,372) (1.6) % Energy Costs: Fuel for power generation 41,717 36,486 5,231 14.3 % Purchased power 39,902 35,585 4,317 12.1 % Gas purchased for resale 37,620 31,617 6,003 19.0 % Deferral of energy - electric - net (19,335) (12,670) (6,665) 52.6 % Deferral of energy - gas - net (14,375) (1,240) (13,135) 1,059.3 % Energy efficiency program costs 1,878 3,651 (1,773) (48.6) % Total Costs $ 87,407 $ 93,429 $ (6,022) (6.4) % Cost by Segment: Electric $ 64,162 $ 63,052 1,110 1.8 % Gas 23,245 30,377 (7,132) (23.5) % $ 87,407 $ 93,429 $ (6,022) (6.4) % Gross Margin by Segment: Electric $ 108,465 $ 106,754 $ 1,711 1.6 % Gas 16,484 15,545 939 6.0 % $ 124,949 $ 122,299 $ 2,650 2.2 % Three Months Ended March 31, 2013 2012 Variance % Change SPPC Heating 2,285 2,128 157 7.4 % Cooling - - N/A N/A Electric Operating Revenue Three Months Ended March 31, Operating Revenues: 2013 2012 Variance % Change Residential $ 62,978 $ 61,360 $ 1,618 2.6 % Commercial 56,886 58,712 (1,826) (3.1) % Industrial 34,640 33,070 1,570 4.7 % Retail revenues 154,504 153,142 1,362 0.9 % Other 18,123 16,664 1,459 8.8 % Total Operating Revenues $ 172,627 $ 169,806 $ 2,821 1.7 % Retail sales in thousands of MWhs Residential 629 600 29 4.8 % Commercial 650 659 (9) (1.4) % Industrial 668 633 35 5.5 % Retail sales in thousands of MWhs 1,947 1,892 55 2.9 % Average retail revenue per MWh $ 79.35 $ 80.94 $ (1.59) (2.0) % Gas Operating Revenue Three Months Ended March 31, 2013 2012 Variance % Change Gas Operating Revenues: Residential $ 22,545 $ 26,557 $ (4,012) (15.1) % Commercial 8,719 10,966 (2,247) (20.5) % Industrial 2,278 2,715 (437) (16.1) % Retail Revenues 33,542 40,238 (6,696) (16.6) % Wholesale Revenues 5,325 4,830 495 10.2 % Miscellaneous 862 854 8 0.9 % Total Gas Revenues $ 39,729 $ 45,922 $ (6,193) (13.5) % Retail sales in thousands of Dths Residential 4,136 3,708 428 11.5 % Commercial 2,076 1,879 197 10.5 % Industrial 533 476 57 12.0 % Retail sales in thousands of Dths 6,745 6,063 682 11.2 % Average retail revenue per Dth $ 4.97 $ 6.64 $ (1.67) (25.1) % Three Months Ended March 31, 2013 2012 Variance % Change Energy Costs Fuel for power generation $ 41,717 $ 36,486 $ 5,231 14.3 % Purchased power 39,902 35,585 4,317 12.1 % Total Energy Costs $ 81,619 $ 72,071 $ 9,548 13.2 % MWhs MWhs Generated (in thousands) 1,147 1,178 (31) (2.6) % Purchased Power (in thousands) 1,105 1,011 94 9.3 % Total MWhs 2,252 2,189 63 2.9 % Average cost per MWh Average fuel cost per MWh of Generated Power $ 36.37 $ 30.97 $ 5.40 17.4 % Average cost per MWh of Purchased Power $ 36.11 $ 35.20 $ 0.91 2.6 % Average total cost per MWh $ 36.24 $ 32.92 $ 3.32 10.1 % Gas Purchased for Resale Three Months Ended March 31, 2013 2012 Variance % Change Gas purchased for resale $ 37,620 $ 31,617 $ 6,003 19.0 % Gas purchased for resale (in thousands of Dths) 8,427 8,274 153 1.8 % Average cost per Dth $ 4.46 $ 3.82 $ 0.64 16.8 % Deferred Energy Three Months Ended March 31, 2013 2012 Variance % Change Deferral of energy - electric - net $ (19,335) $ (12,670) $ (6,665) 52.6 % Deferral of energy - gas - net (14,375) (1,240) (13,135) 1,059.3 % $ (33,710) $ (13,910) $ (19,800) 142.3 % Other Operating Expenses Three Months Ended March 31, 2013 2012 Variance % Change Energy efficiency program costs $ 1,878 $ 3,651 (1,773) (48.6) % Other operating expenses $ 35,805 $ 36,432 (627) (1.7) % Maintenance $ 6,831 $ 9,453 (2,622) (27.7) % Depreciation and amortization $ 27,341 $ 25,872 1,469 5.7 % Interest Expense Three Months Ended March 31, 2013 2012 Variance % Change Interest expense (net of AFUDC-debt: $294 and $416) $ 15,525 $ 16,973 (1,448) (8.5) % Other Income (Expense) Three Months Ended March 31, 2013 2012 Variance % Change Interest expense on regulatory items $ (25) $ (186) 161 (86.6) % AFUDC-equity $ 523 $ 519 4 0.8 % Other income $ 1,140 $ 2,183 (1,043) (47.8) % Other expense $ (1,248) $ (1,335) 87 (6.5) % 2013 Expected Maturities Fair 2013 2014 2015 2016 2017 Thereafter Total Value Long-Term Debt NVE Fixed Rate $ - $ 195,000 $ - $ - $ - $ 315,000 $ 510,000 $ 575,444 Average Interest Rate - 2.81 % - - - 6.25 % 4.93 % - NPC Fixed Rate $ - $ 125,000 $ 250,000 $ 210,000 $ - $ 2,545,000 $ 3,130,000 $ 3,873,718 Average Interest Rate - 7.38 % 5.88 % 5.95 % - 6.47 % 6.42 % - Variable Rate $ 98,100 $ - $ - $ - $ - $ 75,675 $ 173,775 $ 170,737 Average Interest Rate 0.61 % - - - - 0.56 % 0.59 % - SPPC Fixed Rate $ 250,000 $ - $ - $ 450,000 $ - $ 251,742 $ 951,742 $ 1,115,492 Average Interest Rate 5.45 % - - 6.00 % - 6.75 % 6.05 % - Variable Rate $ - $ - $ - $ - $ - $ 214,675 $ 214,675 $ 184,895 Average Interest Rate - - - - - 0.56 % 0.56 % - TOTAL DEBT $ 348,100 $ 320,000 $ 250,000 $ 660,000 $ - $ 3,402,092 $ 4,980,192 $ 5,920,286 Total Number of Shares Maximum Number of Purchased as Part of Shares that may yet be Total Number of Average Price Publicly Announced Purchased Under the Period Shares Purchased (1) Paid Per Share Plans or Programs Plans or Programs January 1 - January 31, 2013 197,178 $ 18.49 N/A N/A February 1 - February 28, 2013 - - N/A N/A March 1 - March 31, 2013 - - N/A N/A Total 197,178 $ 18.49 - - (1) Represents shares of common stock purchased on the open market to provide shares to participants under various NVE stock compensation plans. These purchases were not made pursuant to a publicly announced stock repurchase plan or program. Date: May /s/ E. Kevin Bethel E. Kevin Bethel Senior Vice President and Chief Financial Officer (Mark One)þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2013OR¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO Registrant, Address ofI.R.S. EmployerPrincipal Executive OfficesIdentificationState ofand Telephone NumberNumberIncorporation000-52378 NEVADA POWER COMPANY 88-0420104 1-08788NV ENERGY, INC.88-0198358Nevada(702) 402-50002-28348NEVADA POWER COMPANY d/b/a88-0420104NevadaNV ENERGY6226 West Sahara AvenueLas Vegas, Nevada 89146(702) 402-50000-00508SIERRA PACIFIC POWER COMPANY d/b/a88-0044418NevadaNV ENERGYP.O. Box 10100(6100 Neil Road)Reno, Nevada 89520-0400 (89511)(775) 834-4011 þ T Noo (Response applicable to all registrants)website,Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ T Noo (Response applicable to all registrants)anythe registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large"large accelerated filer",filer," "accelerated filer", "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.NV Energy, Inc.: þo ox o Nevada Power Company:Large accelerated fileroAccelerated filer oNon-accelerated filer þ Smaller reporting company o Sierra Pacific Power Company:Large accelerated filer oAccelerated filer oNon-accelerated filer þ Smaller reporting company o þT (Response applicable to all registrants)Indicate the numbershares outstanding common stock of each of the issuer’s classes of Common Stock, as of the latest practicable date.the sole holderan indirect, wholly owned subsidiary of theBerkshire Hathaway Energy Company, formerly known as MidAmerican Energy Holdings Company. As of April 30, 2014, 1,000 shares of outstanding Common Stock,common stock, $1.00 stated value, of Nevada Power Company.NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.This combined Quarterly Report on Form 10-Q is separately filed by NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by NV Energy, Inc. and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Nevada Power Company. Information contained in this document relating to Sierra Pacific Power Company is filed by NV Energy, Inc. and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Sierra Pacific Power Company.SIERRA PACIFIC POWER COMPANYQUARTERLY REPORTS ON FORM 10-QFOR THE QUARTER ENDED MARCH 31, 2013TABLE OF CONTENTSPART I – FINANCIAL INFORMATIONNevada Power Company and Certifications57 Company Nevada Power Company and its subsidiaries Berkshire Hathaway Energy Berkshire Hathaway Energy Company (formerly MidAmerican Energy Holdings Company) NV Energy NV Energy, Inc. Sierra Pacific Sierra Pacific Power Company, an electric and natural gas utility wholly owned by NV Energy Higgins Generating Station 530-megawatt generating facility in Nevada Lenzie Generating Station 1,102-megawatt generating facility in Nevada Navajo Generating Station 2,250-megawatt generating facility in Arizona ON Line 500-kilovolt transmission line connecting the Company and Sierra Pacific Reid Gardner Generating Station 557-megawatt generating facility in Nevada 2ACRONYMS AND TERMS(The following common acronyms and terms are found in multiple locations within the document)Certain Industry Terms Acronym/TermMeaning2012 Form 10-KNVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012AFUDC-debt Borrowed Funds Used During ConstructionAFUDC-equityAllowance for Equity Funds Used During ConstructionAROAsset Retirement ObligationBODBoard of DirectorsBTERBase Tariff Energy RateBTGRBase Tariff General RateCA ISOCalifornia Independent System Operator CorporationCalifornia AssetsSPPC's California electric distribution and generation assetsCalPecoCalifornia Pacific Electric CompanyCDDCooling degree daysCDWRCalifornia Department of Water ResourcesCIACContributions in Aid of ConstructionCWIPConstruction Work-in-ProgressdbaDoing business asDEAADeferred Energy Accounting AdjustmentDthDecathermEEIREnergy Efficiency Implementation RateEEPREnergy Efficiency Program RateEPAEPSEarnings per ShareFASBFinancial Accounting Standards BoardFASCFASB Accounting Standards CodificationFERCFitchFitch Ratings, Ltd.Ft. Churchill Generating Station226 megawatt nominally rated Fort Churchill Generating StationGAAPGenerally Accepted Accounting Principles in the United StatesGBTGreat Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLCGBT-SouthGreat Basin Transmission South, LLC, a wholly owned subsidiary of GBTGRCGeneral Rate CaseHarry Allen Generating Station642 megawatt nominally rated Harry Allen Generating StationHDDHeating degree daysHiggins Generating Station598 megawatt nominally rated Walter M. Higgins, III Generating StationkVKilovoltLenzie Generating Station1,102 megawatt nominally rated Chuck Lenzie Generating StationMohave Generating Station1,580 megawatt nominally rated Mohave Generating StationMoody’sMoody’s Investors Services, Inc.MWMegawattMWhMegawatt hourNavajo Generating Station255 megawatt nominally rated Navajo Generating StationNEICONevada Electric Investment CompanyNERCNorth American Electric Reliability CorporationNinth CircuitUnited States Court of Appeals for the Ninth CircuitNOLNet Operating LossNPCNevada Power Company d/b/a NV EnergyNPC Credit Agreement$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,N.A., as administrative agent for the lenders a party theretoNPC IndentureNPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bankof New York Mellon Trust Company, N.A., as TrusteeNRSRONationally Recognized Statistical Rating OrganizationNVENV Energy, Inc.NV EnergizeA smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will providecustomers the ability to more directly manage their energy usageON Line250 mile 500 kV transmission line connecting NVE’s northern and southern service territoriesPortfolio StandardNevada Renewable Energy Portfolio StandardPUCNReid Gardner Generating Station325 megawatt nominally rated Reid Gardner Generating StationREPRRenewable Energy Program RateRORRate of ReturnS&PStandard & Poor’s3
Item 1. Financial StatementsSalt RiverSalt River ProjectSECUnited States Securities and Exchange CommissionSilverhawk Generating Station395 megawatt nominally rated Silverhawk Generating StationSmart MetersAdvanced service delivery meters installed as part of the NV Energize projectSNWASouthern Nevada Water AuthoritySPPCSierra Pacific Power Company d/b/a NV EnergySPPC Credit Agreement$250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells FargoBank, N.A., as administrative agent for the lenders a party theretoSPPC IndentureSPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC andthe Bank of New York Mellon Trust Company, N.A., as TrusteeSTPRSolar Thermal Program RateTerm Loan$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank,N.A., as administrative agent for the lenders a party theretoTMWATruckee Meadows Water AuthorityTracy Generating Station541 megawatt nominally rated Frank A. Tracy Generating StationTREDTemporary Renewable Energy DevelopmentTUATransmission Use and Capacity Exchange Agreement with GBT-SouthU.S.United States of AmericaUtilitiesNevada Power Company and Sierra Pacific Power CompanyValmy Generating Station261 megawatt nominally rated Valmy Generating StationVIEVariable Interest EntityWSPPWestern Systems Power Pool4ITEM 1.May 2, 2014 FINANCIAL STATEMENTSNV ENERGY, INC. As of March 31, December 31, 2014 2013 ASSETS Current assets: Cash and cash equivalents $ 99 $ 126 Accounts receivable, net 231 227 Inventories 70 73 Regulatory assets 64 81 Deferred income taxes 135 152 Other current assets 50 39 Total current assets 649 698 Property, plant and equipment, net 6,984 6,992 Regulatory assets 1,033 1,057 Other assets 88 88 Total assets $ 8,754 $ 8,835 LIABILITIES AND SHAREHOLDER'S EQUITY Current liabilities: Accounts payable $ 202 $ 240 Accrued interest 42 61 Accrued property, income and other taxes 25 29 Accrued employee expenses 9 6 Regulatory liabilities 68 74 Current portion of long-term debt 260 22 Customer deposits and other 80 74 Total current liabilities 686 506 Long-term debt 3,307 3,555 Regulatory liabilities 317 312 Deferred income taxes 1,285 1,298 Other long-term liabilities 262 274 Total liabilities 5,857 5,945 Commitments and contingencies (Note 8) Shareholder's equity: Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding — — Other paid-in capital 2,308 2,308 Retained earnings 592 586 Accumulated other comprehensive loss, net (3 ) (4 ) Total shareholder's equity 2,897 2,890 Total liabilities and shareholder's equity $ 8,754 $ 8,835 The accompanying notes are an integral part of the consolidated financial statements. COMPREHENSIVE INCOMEDollarsAmounts in Thousands, Except Share Amounts)(Unaudited)5 Three-Month Periods Ended March 31, 2014 2013 Operating revenue $ 417 $ 370 Operating costs and expenses: Cost of fuel, energy and capacity 203 142 Operating and maintenance expense 82 99 Depreciation and amortization 66 65 Property and other taxes 11 10 Total operating costs and expenses 362 316 Operating income 55 54 Other income (expense): Interest expense, net of allowance for debt funds (51 ) (53 ) Allowance for equity funds — 2 Other, net 6 5 Total other income (expense) (45 ) (46 ) Income before income tax expense 10 8 Income tax expense 4 3 Net income $ 6 $ 5 The accompanying notes are an integral part of these consolidated financial statements. BALANCE SHEETSDollarsAmounts in Thousands, Except Share Amounts)(Unaudited)6 Accumulated Other Other Total Common Stock Paid-in Retained Comprehensive Shareholder's Shares Amount Capital Earnings Loss, Net Equity Balance at December 31, 2012 1,000 $ — $ 2,308 $ 619 $ (5 ) $ 2,922 Net income — — — 5 — 5 Dividends declared — — — (50 ) — (50 ) Balance at March 31, 2013 1,000 $ — $ 2,308 $ 574 $ (5 ) $ 2,877 Balance at December 31, 2013 1,000 $ — $ 2,308 $ 586 $ (4 ) $ 2,890 Net income — — — 6 — 6 Other — — — — 1 1 Balance at March 31, 2014 1,000 $ — $ 2,308 $ 592 $ (3 ) $ 2,897 The accompanying notes are an integral part of these consolidated financial statements. 7DollarsAmounts in Thousands)(Unaudited)8 Three-Month Periods Ended March 31, 2014 2013 Cash flows from operating activities: Net income $ 6 $ 5 Adjustments to reconcile net income to net cash flows from operating activities: Depreciation and amortization 66 65 Deferred income taxes and amortization of investment tax credits 4 3 Allowance for equity funds — (2 ) Amortization of deferred energy 13 (27 ) Deferred energy (2 ) (17 ) Amortization of other regulatory assets 12 22 Other, net 5 1 Changes in other operating assets and liabilities: Accounts receivable and other assets (32 ) 40 Inventories 3 (3 ) Accounts payable and other liabilities (42 ) (50 ) Net cash flows from operating activities 33 37 Cash flows from investing activities: Capital expenditures (58 ) (59 ) Contributions in aid of construction and customer advances 9 6 Net cash flows from investing activities (49 ) (53 ) Cash flows from financing activities: Repayments of long-term debt (11 ) (3 ) Dividends paid — (50 ) Net cash flows from financing activities (11 ) (53 ) Net change in cash and cash equivalents (27 ) (69 ) Cash and cash equivalents at beginning of period 126 201 Cash and cash equivalents at end of period $ 99 $ 132 The accompanying notes are an integral part of these consolidated financial statements. NV ENERGY, INC.CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY(Dollars in Thousands, Except Share Amounts)(Unaudited)9CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(Dollars in Thousands)(Unaudited)10NEVADA POWER COMPANY(Dollars in Thousands, Except Share Amounts)(Unaudited)1112NEVADA POWER COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS(Dollars in Thousands)(Unaudited)13NEVADA POWER COMPANYCONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY(Dollars in Thousands, Except Share Amounts)(Unaudited)14SIERRA PACIFIC POWER COMPANYCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(Dollars in Thousands)(Unaudited)15SIERRA PACIFIC POWER COMPANY(Dollars in Thousands, Except Share Amounts)(Unaudited)1617SIERRA PACIFIC POWER COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS(Dollars in Thousands)(Unaudited)18SIERRA PACIFIC POWER COMPANYCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY(Dollars in Thousands, Except Share Amounts)(Unaudited)19CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESThe significant accounting policies for both utilitynon-utility operations are as follows:Basis of PresentationThe consolidated financial statements includeOperationsaccounts"Company"), is a wholly owned subsidiary of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC,("NV Energy"), a holding company that also owns Sierra Pacific Communications, LandsPower Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States utility company serving electric retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Sierra,Berkshire Hathaway Energy Company ("Berkshire Hathaway Energy"), formerly known as MidAmerican Energy Holdings Company. Berkshire Hathaway Energy is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. Berkshire Hathaway Energy is a consolidated subsidiary of Berkshire Hathaway Inc., NVE Insurance Company, Inc. and Sierra Gas Holding Company. All intercompany balances and transactionseliminatedprepared in consolidation.consolidated financial statementsthe unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statementsunaudited Consolidated Financial Statements and the reported amounts of certain revenuesrevenue and expenses during the reporting period. Actual results couldmay differ from these estimates. In the opinionestimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessaryNotes to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statementsConsolidated Financial Statements included in the 2012Company's Annual Report on Form 10-K. The results of operations and cash flows of NVE, NPC and SPPC10-K for the three monthsyear ended December 31, 2013 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2013, are not necessarily indicative of the results to be expected for the full year.PoliciesConsolidations of VIEsTo identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities. The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. As of March 31, 2013, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.Recent Accounting Standards Update Other Comprehensive Income (ASU 220)In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Pronouncementsreinstated certain portionsAccounting Standards Codification Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the deferred amendment. The reinstated amendmentobligation is applied prospectivelyfixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. This guidance is effective for NVEinterim and the Utilities as ofannual reporting periods beginning after December 15, 2013. The Company adopted this guidance on January 1, 2013.2014. The adoption of this guidance doesdid not have a material impact on the presentationCompany's disclosures included within Notes to Consolidated Financial Statements.financial statementsfollowing (in millions): As of March 31, December 31, 2014 2013 Utility plant in-service: Generation $ 3,821 $ 3,789 Distribution 2,960 2,936 Transmission 1,751 1,743 General and intangible plant 659 645 Utility plant in-service 9,191 9,113 Accumulated depreciation and amortization (2,286 ) (2,217 ) Utility plant in-service, net 6,905 6,896 Other non-regulated, net of accumulated depreciation and amortization 4 3 6,909 6,899 Construction work-in-progress 75 93 Property, plant and equipment, net $ 6,984 $ 6,992 NVEcalendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. As a result, the Company has deferred revenue recognition for energy efficiency implementation rates collected and the Utilities. Balance Sheet Offsetting Disclosures (ASU 210)In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting)has recorded a liability of assets and liabilities$3 million on the face of the financial statements. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements. The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance does not have a material impact on the disclosure requirements for NVE and the Utilities.20The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other information includes amounts below the quantitative thresholds for separate disclosure.Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities. See Note 1, Summary of Significant Accounting Policies, of the 2012 Form 10-K for further information regarding energy efficiency program costs. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands). 21NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding deferred energy accounting by the Utilities.The following deferred energy amounts were included in the consolidated balance sheetsConsolidated Balance Sheets as of March 31, 2013 (dollars in thousands):Pending Regulatory Actions Nevada Power2014. In February 2014, the Company NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate FilingsIn March 2013, NPC filed an application forwith the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIRenergy efficiency implementation rate. The Company proposed to suspend collection of the energy efficiency implementation rate on October 1, 2014, and EEPRdefer implementation of a new energy efficiency implementation rate elements. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the table above. The March 2013 application includes the following changes in revenue requirement (dollars in millions):Sierra Pacific Power Company SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate FilingsIn March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.The March 2013 application includes the following changes in revenue requirement includes the following (dollars in millions):22SPPC Nevada Gas DEAA and REPR Rate FilingsIn March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above. The amounts requested in this filing result in an overall decrease in revenue requirement of $0.2 million with an anticipated effective date of October 2013.FERC Matters NPC NPC 2012 FERC Transmission Rate CaseOctober 2012, NPCMay 2013, the Company, along with Sierra Pacific, filed an application with the FERC to resetestablish single system transmission and ancillary service rates that were last set in 2003.rates. The combined filing requested incremental rate changes requested in this filing would result in an overall annual revenue increaserelief of $11.3 million. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases$17 million annually to be effective January 1, 2013. All rates are2014. On August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to final approval byrefund, and set the FERC. However, atcase for hearing or settlement discussions. On January 1, 2014, the Company implemented the filed rates in this case subject to refund as set forth in FERC's order. As of March 31, 2014, the Company accrued $3 million for amounts subject to rate refund, which is included in customer deposits and other on the Consolidated Balance Sheets. At this time management is unable to determine the final revenue impact of the case. SPPC SPPC 2012 FERC Transmission Rate CaseIn October 2012, SPPC filed an application with the FERC to reset transmissionancillary service ratesa supplemental executive retirement plan and a restoration plan (collectively, "Non-Qualified Pension Plans") that were last set in 2007provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and 2003, respectively. The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million. In December 2012, FERC issued an order which suspendedCafeteria Plan provides certain rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. All rates are subject to final approval by the FERC.However, at this time management is unable to determine the final revenue impactpostretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the case.23NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands): Substantially all utility plant is subjectCompany. Amounts attributable to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage bonds are issued.NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTSThe March 31, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.The total fair value of NVE’s consolidated long-term debt at March 31, 2013 is estimated to be $5.9 billion based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value was estimated to be $5.9 billion as of December 31, 2012.The total fair value of NPC’s consolidated long-term debt at March 31, 2013, is estimated to be $4.0 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value was estimated to be $4.1 billion at December 31, 2012.The total fair value of SPPC’s consolidated long-term debt at March 31, 2013, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value was estimated to be $1.3 billion as of December 31, 2012. 24NOTE 6.RETIREMENT PLAN AND POST-RETIREMENT BENEFITS NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities. NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPCCompany were allocated from NV Energy based upon the current, or in the case of the retirees, previous, employment location. Certain grandfatheredOffsetting regulatory assets and union employees are covered underliabilities have been recorded related to the amounts not yet recognized as a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees. A summary of the componentscomponent of net periodic pensionbenefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive income. As of March 31, December 31, 2014 2013 Qualified Pension Plan: Other assets $ 11 $ 13 Non-Qualified Pension Plans: Customer deposits and other (4 ) (4 ) Other long-term liabilities (8 ) (8 ) Other Postretirement Plans: Other long-term liabilities (7 ) (7 ) postretirement costscommodity price risk as it has an obligation to serve retail customer load in its service territory. The Company's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power are recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. The Company does not engage in proprietary trading activities. Customer Other Deposits and Long-term Other Liabilities Total As of March 31, 2014 $ (8 ) $ (27 ) $ (35 ) As of December 31, 2013 $ (9 ) $ (38 ) $ (47 ) (1) Unit of March 31, December 31, Measure 2014 2013 Electricity sales Megawatt hours 4 4 Natural gas purchases Decatherms 129 118 months ended March 31 follows. This summary is based on a December 31, measurement date (dollars in thousands):As discussed in Note 10, Retirement Plan and Postretirement Benefits,recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the 2012 Form 10-K, NVE offeredevent of a voluntary lump sum pension payoutcredit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to former employees not currentlydemand "adequate assurance," in the event of retirement age but eligible for future benefitsa material adverse change in creditworthiness. These rights can vary by contract and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation.by counterparty. As of March 31, 2013, NVE expects to payout an additional $11.0 million in lump sum pension pay outs2014, credit ratings from the pensionthree recognized credit rating agencies were investment grade.(7) Fair Value Measurements during 2013. Duringand liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three monthslevels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:NVE made no contributions to either(in millions): 2014 Beginning balance $ (47 ) Changes in fair value recognized in regulatory assets 12 Ending balance $ (35 ) plans. AtCompany's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present time, NVE expects neithervalue of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions): As of March 31, 2014 As of December 31, 2013 Carrying Fair Carrying Fair Value Value Value Value Long-term debt $ 3,067 $ 3,661 $ 3,071 $ 3,596 (8) Commitments and Contingencies will requireto retire 800 MWs of coal plants, starting as soon as December 31, 2014;funding in 2013 inelectric generating capacity; andmeetreview by a Nevada Legislative commission and which must be filed with the minimum funding level requirements defined by the Pension Protection ActSecretary of 2006. However, NVEState, and the Utilities have included in their 2013 assumptions funding levels similar toregulations became effective March 2014. In May 2014, the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.25NOTE 7. COMMITMENTS AND CONTINGENCIESEnvironmentalNPC NEICONEICO, a wholly-owned subsidiaryCompany filed its Emission Reduction Capacity Replacement Plan proposing, among other items, the retirement of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options for this property going forward, including reclamation or sale to a third party.On units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a plan to replace the generation capacity being retired, as required by Senate Bill No. 123. The Emissions Reduction and Capacity Replacement Plan includes the issuance of requests for proposals for 300 MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 274-MW natural gas co-generating facility in 2014; the acquisition of a 222-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed Emissions Reduction and Capacity Replacement Plan, which are subject to PUCN approval.4, 2011, NPCthe Company received a request for information from the EPA-RegionEnvironmental Protection Agency Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’sthe Company's Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-3. Unit 4 of the facility is co-owned with the CDWR. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant. NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, NPC cannot predict the impact, if any, associated with this information request.SPPC Valmy Generating StationOn June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’sEnvironmental Protection Agency's Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPAEnvironmental Protection Agency relating to the plant. SPPCThe Company completed its responseresponses to the EPA in December 2009Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, SPPCthe Company cannot predict the impact, if any, associated with this information request. NPC and SPPC Regional Haze Rules In 2005, the EPA finalized amendments its Regional Haze Rules 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 U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP.For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015.On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada. On March 26, 2013,the EPA granted reconsideration of the compliance date for the BART retrofits for Units 1, 2, and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015, to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action. The comment period for this action is scheduled to close on May 30, 2013. NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE has received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2. NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned 26the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPAannounced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline forreducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impacton the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion inadditional emission controls at the plant of which NPC’s ownership share is 11.3%.The comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested a 90-day extension, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners. In March, 2013, the EPA granted a 90-day extension to August 5, 2013. Prior to the close of the comment period, the EPA is expected to hold public hearings in Arizona.Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear,and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predictat this timethe ultimate financial impact to the Navajo Generating Station operations or what other alternativelegal actions the ownership may decide to take at this time. Mercury and Air Toxics Standards (MATS)In December 2011, the EPA signed for publication in the Federal Registera final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule, requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the applicationarising out of the Maximum Achievable Control Technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC. Note that the actual cost will be dependent upon final engineering design.The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order allow for additional testing of various mercury control strategies. Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo units, a cost estimate is unable to be determined at this time.Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.Other Environmental MattersNVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. In addition, NVE and the Utilities may also be subject to future state or federal regulations. Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility. If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations. In 2008, NPC signed an Administrative Orderbusiness. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of Consent (AOC) as owner and operatorlegal actions, some of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owners and operating agent of Unit No. 4. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs. However, actual costs of work under the AOCwhich assert or may vary significantly once the scope of work is defined and additional site characterization has been completed. NVE and the Utilitiesassert claims or seek to continually comply with environmental regulations; however, given the uncertainties involvedimpose fines, penalties and other costs in the federal, statesubstantial amounts and local regulatory environment, future costs to comply may be material.27Litigation ContingenciesNPC Peabody Western Coal Company – Royalty ClaimNPC owns an 11% interest inNavajo Generating Station, which isUnited States through the Bureau of Land Management 2,675 acres of land located in northern Arizona and operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.In June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station.The DC Lawsuit asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising outNorth Las Vegas, Nevada. A small portion of the DC Lawsuit. In July 2008,land is traversed by a 500 kilovolt transmission line owned by the court dismissed all counts against NPC, two without prejudice to their possible re-filing.In August 2011, all claims in the DC Lawsuit were dismissedCompany and sited pursuant to a settlement agreement amongpre-existing right-of-way grant from the Navajo Nation, Peabody, Salt RiverBureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, SCE. Atif it did, the requestamount owed to NLI under the right-of-way grant. NLI eventually "terminated" the right-of-way grant and brought claims against the Company for breach of Salt River, NPC contributed an immaterial amount towardcontract, inverse condemnation and trespass. The Company counterclaimed for express condemnation of a perpetual easement over the settlementright-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada ("Eighth District Court"). In September 2013, the Eighth District Court awarded NLI $1 million for unpaid rent and $5 million for inverse condemnation, plus interest and attorneys' fees, bringing the total judgment to $12 million. The Eighth District Court also found the Company was entitled to judgment in its favor on its counterclaim for condemnation of the DC Lawsuit based on its 11% ownership stake inright-of-way corridor. The Company has appealed to the Navajo Generating Station. SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. NPC has not agreed to contribute to SCE’s portion of the DC Lawsuit settlement. Management has discussed the matters with SCE, but does not believe the impact of any claim by, or settlement with, SCE will be material to NPC. SPPC Farad DamIn June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million. One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or, alternatively, SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim. The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers. The insurers contested the extent and amount of insurance coverage. Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost. In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit.Supreme Court. Management cannot assess or predict the outcome orof the case at this time.the District Court decisions at this time, but they are not expected to be material to SPPC. Other Legal MattersNVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.Other Commitments NPC and SPPC ON Line TUADuring the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities 28expect to get regulatory recovery. For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of March 31, 2013, capitalized construction costs associated with GBT’s 75% interest of $297.5 million and $17.0 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.NOTE 8. EARNINGS PER SHARE (NVE)The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. NOTE 9.COMMON STOCK AND OTHER PAID-IN CAPITALDividendsThe following dividend declarations were made by the BOD of NVE:Declaration DateAmountPayable DateShareholders of Record DateFebruary 7, 2013$0.19 March 20, 2013March 5, 2013May 8, 2013$0.19 June 19, 2013June 4, 2013On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively. For the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million.Treasury StockNVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program. All shares repurchased are held as treasury stock and may be reissued 29upon exercise or settlement of the stock compensation award. Treasury stock is accounted for using the cost method. During the three months ended March 31, 2013, NVE repurchased 197,178 shares of common stock for approximately $3.7 million. During the three months ended March 31, 2013, NVE re-issued 644,536 treasury shares to satisfy employee benefit plans.30ITEMItem 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSForward-Looking Statements and Risk FactorsThe information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:Operational Risks·economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;·changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;·construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;·security breaches of our information technology or supervisory control and data systems, or the systems of others upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information; ·unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the southwestern U.S., and have other adverse effects on our business;·employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, and the ability to adjust the labor cost structure to changes in growth within our service territories;·whether the Utilities’ newly installed advanced metering systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;·changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;·explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;·the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;·changes in the business of the Utilities’ major customers engaged in mining or gaming, including availability and cost of capital or power demands, which may result in changes in the demand for the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;·the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;·unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.31Regulatory/Legislative Risks·unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;·the effect of existing or future Nevada or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;·whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada; and·changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.Environmental Risks·changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.Liquidity and Capital Resources Risks·whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs) and/or power, or a ratings downgrade;·wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;·the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;·whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions contained in NVE's and the Utilities' agreements;·whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act; and·further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.32NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTSIn reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties that are specific to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;•have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;•may apply standards of materiality in a way that is different from what may be viewed as material to investors; and•were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements and are subject to more recent developments.Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.NOTE REGARDING STATISTICAL DATAThe statistical data used throughout this 10-Q, other than data relating specifically to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources. NVE and the Utilities did not commission any of these publications or reports. These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information. While NVE and the Utilities believe that each of these studies and publications is reliable, NVE and the Utilities have not independently verified such data and make no representation as to the accuracy of such information.33EXECUTIVE OVERVIEWManagement’s Management's Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes discussion of the following:•Critical Accounting Policies and Estimates:•Recent Pronouncements•For each of NVE, NPC and SPPC:•Results of Operations•Analysis of Cash Flows•Liquidity and Capital Resources•Regulatory Proceedings (Utilities)NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas. Other operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.The Utilities are regulated by the PUCN with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.The Utilities’Company's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPCThe Company is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under shortshort- and long termlong-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities.Company. Additionally, the timely recovery of purchased power, and fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of the Utilities. OverviewCompany.Major Factors Affecting certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.NVE recognized for the First Quarter of 2014 and 2013 First Quarter 2014 2013 Change Gross margin (in millions): Operating revenue $ 417 $ 370 $ 47 13 % Cost of fuel, energy and capacity 203 142 61 43 Gross margin $ 214 $ 228 $ (14 ) (6 ) Sales (GWh): Residential 1,465 1,611 (146 ) (9 )% Commercial 933 916 17 2 Industrial 1,629 1,635 (6 ) — Other 53 48 5 10 Total retail 4,080 4,210 (130 ) (3 ) Wholesale 5 14 (9 ) (64 ) Total sales 4,085 4,224 (139 ) (3 ) Average number of retail customers (in thousands) 868 851 17 2 % Average retail revenue per MWh $ 99.89 $ 86.11 $ 13.78 16 % Heating degree days 668 1,050 (382 ) (36 )% Cooling degree days 34 86 (52 ) (60 ) Sources of energy (GWh): Coal 1,228 473 755 * Natural gas 2,269 3,394 (1,125 ) (33 ) Total energy generated 3,497 3,867 (370 ) (10 ) Energy purchased 811 643 168 26 Total 4,308 4,510 (202 ) (4 ) * Not meaningful incomeresidential usage of $21.5$12 million, primarily due to a decrease in heating degree days during the winter;the three months ended March 31, 2013,2014 compared to $12.22013 primarily due to a decrease in construction activity, including ON Line being placed in service in December 2013.the same period in 2012. The increase in net income is2014 compared to 2013 primarily due to the following pre-tax items:•An increase in gross margin of $9.3 million; see the Utilities’ respective Results of Operations for further discussion of gross margin;•A decrease in maintenance expense of $7.6 million due to the timing of outages; see the Utilities’ respective Results of Operations for further discussion; and•A decrease in interest expense of $4.6 million primarily due to the redemption of NPC’s 6.5%redemption of $125 million Series U 7.375% General and Refunding Mortgage Notes Series I in April 2012 and an increase in AFUDC-debt.NVE TransformationBeginning in 2006, NVE committedDecember 2013.an energy strategy2013 primarily due to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as, expanding our transmission capability in an efforthigher interest income on under collected deferred energy.reduce our reliance on purchased power. The implementation of this strategy required significant amounts of liquidity and capital. To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs. At the same time, management worked with the PUCN2013 primarily due to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders. The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn their allowable return on their investments while meeting a higher percentage of their load through owned generation. Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continues to improve. Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable. As a result, NVE expects to generate free cash flow in 2013, which may provide NVE the ability to increase its dividend while preserving its ability to invest in new opportunities. Key InitiativesThe economy in Nevada continues to recover slowly. While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment. However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further our ability to increase our common stock dividend, strengthen our capital structure and consider new investment opportunities. These initiatives should enable us to contain operating and 34maintenance costs while effectively managing our regulatory environmentLiquidity and continuing to promote and improve a safe and reliable work environment. These key initiatives are discussed below.Continuous Improvement ofSafety The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into its business operations and culture. These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions. Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company. Construction of ON Line and One Company MergerON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in late 2013, will connect NVE’s southern and northern service territories. Pending certain state and federal regulatory approvals, ON Line will provide:•Ability to dispatch energy jointly throughout the state;•Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada which will enhance NVE’s ability to meet its Portfolio Standard;•Ability to optimize its generating and transmission facilities to benefit its customers; and•The opportunity for NVE to merge NPC and SPPC (the “One Company” merger). A merger application is expected to be filed with the PUCN and FERC in June 2013.Empower Customers through Focused Service and Efficiency ProgramsNV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management. The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options. the installation of the Smart Meters is nearly complete. NV Energize system provides more convenience forchange was primarily due to a one-time bill credit paid to retail customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests. The system also enables NVE to launch new customer programs. Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway. New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information. An enhanced air conditioning demand response program was launched in the fourth quarter. It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability. Similar programs for commercial customers are under development.Managing Generation Portfolio Within Environmental ComplianceAs discussed in more detail in Note 7, Commitments and Contingencies, of the Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules. The implementation costs of the Regional Haze Rules are significant. Therefore, NVE must balance the cost of implementing the retrofits associated with the Regional Haze Rule withmerger between Berkshire Hathaway Energy and NV Energy, intercompany transactions related to ON Line, and increased rent payments related to the effect currentON Line transmission use agreement, partially offset by reduced refunds to customers for previously over-collected deferred energy costs and future load requirements, retirements of generating stations, including the effects of NVision discussed below, and plant outages will have on its ability to serve its customers reliably. Investment opportunitiesNVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy. In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.Proposed Legislationan increase in NevadaThe Nevada Legislature is currently in session and is expected to complete its session in the second quarter of 2013. The most significant legislation under consideration that would directly impact NVE is Senate Bill 123 (SB 123), which is a bill supported by NVE as part of its NVision initiative. NVision is a comprehensive planenergy rates.reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs. At the time of this filing, management cannot predict whether SB 123 will be adopted in its present or an amended form, or its ultimate impact on NVE and the Utilities.RESULTS OF OPERATIONSNV Energy, Inc. and Other SubsidiariesNVE (Holding Company)The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $6.3 million and $6.3 million of long term debt interest costs for the three monthsthree-month periods ended March 31, 2014 and 2013 and 2012, respectively. 35For the period ended March 31, 2013, NPC paid $50.0 million in dividends to NVE. On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0were $(49) million and $20.0$(53) million, respectively.Other SubsidiariesOther subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.NVE’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, The change was primarily due to an increase in contributions in aid of construction and customer advances.used by financing activities, offset partially by an increase in cash from operating activitiesflows for the three-month periods ended March 31, 2014 and a decrease in cash used by investing activities.Cash from Operating Activities -2013 were $(11) million and $(53) million, respectively. The increase in cash from operating activitieschange was primarily due to increased cash flows from accounts receivablea decrease in dividends, partially offset by $5 million of debt tendered in 2014 as a result of the merger between Berkshire Hathaway Energy and NV Energy and higher balances at December 31, 2012, comparedpayments for capital and financial lease obligations.balances at December 31, 2011, dueIssue Debthigher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012. Also contributing to the increase was a reduction in refunds to customers for previously over collected BTER balances, a reduction in coal and gas purchases, and the receipt of approximately $9.0 million in insurance proceeds related to a previous claim. These increases were offsetissue debt is primarily impacted by an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates.Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to the decrease in construction activity related to the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.Cash used by Financing Activities - Cash used byits financing activities increasedprimarily due to anincrease in dividends to shareholders, a reduction in drawsauthority from the NPC’sPUCN. As of March 31, 2014, the Company has financing authority from the PUCN consisting of authority to: (1) issue additional long-term debt securities of up to $725 million; (2) refinance up to $423 million of long-term debt securities; and (3) maintain a revolving credit facility andof up to $1.3 billion. The Company's revolving credit facility contains a financial maintenance covenant which the repurchase of common stock, which may be reissued to satisfy future equity compensation costs.LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)Overall LiquidityNVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and,Company was in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Another significant use of cash is the refunding of previously over-collected BTER amounts from customers.Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions. Available liquiditycompliance with as of March 31, 2013 was as follows (in millions):NVE and the Utilities’ attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, the Utilities may use their revolving credit facilities in order to meet their liquidity needs. Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.NVE has no debt maturities in 2013.However, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020 prior to ON Line’s commercial operation date expected by December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature in September 2013. To meet these long term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long term debt. The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below). NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013. However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt. In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined. NVE’sand the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources. As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.36However, if energy costs rise at a rapid rate, or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity under such circumstances, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE. Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs. Currently, the Utilities are not operating under a PUCN approved hedging plan. Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner. As of May8, 2013, NVE has approximately $22.9 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries, below). For the three months ended March 31, 2013, NPC paid dividends to NVE of approximately $50.0 million. On May8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities. As discussed, in Note 12, Commitments and Contingencies of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR. The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K.Factors Affecting Liquidity Ability to Issue DebtCertain debt of NVE (holding company) places restrictions on debt incurrence and liens, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four-quarter period on a pro forma basis is at least 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed .70 to 1.00. Under these covenant restrictions, as of March 31, 2013, NVE (consolidated) would be allowed to incur up to $3.2 billion of additional indebtedness. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition. NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt. Effect of Holding Company StructureAs of March 31, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due 2014; and$315 million of unsecured 6.25% Senior Notes due 2020.Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.As of March 31, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $5.0 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.Dividends from SubsidiariesSince NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of March 31, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.entered into bycontain covenants which are currently suspended as the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.Credit RatingsThe liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt. On April 30, 2013, Fitch upgraded NVE’s corporate credit ratings from BB to BB+, and for NPC and SPPC, from BB+ to investment grade BBB-. NPC’s and SPPC’sCompany's senior secured debt is rated investment grade. However, if the Company's senior secured debt ratings fall below investment grade by three NRSRO’s: Fitch, Moody’seither Moody's Investor Service or Standard & Poor's, the Company would be subject to limitations under these covenants.S&P.capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The senior debtavailability and terms under which the Company has access to external financing depends on a variety of factors, including the Company's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry. 2014 Generation development $ 222 Distribution 75 Transmission system investment 30 Other 53 Total $ 380 as follows:Rating AgencyFitch(1)Moody’s(2)S&P(3)NVESr. Unsecured Debt BB+ Ba1 BB+NPCSr. Secured Debt BBB+* Baa1* BBB+*SPPCSr. Secured Debt BBB+* Baa1* BBB+**Investment grade(1)Fitch’s lowest level of “investment grade” credit rating is BBB-.(2)Moody’s lowest level of “investment grade” credit rating is Baa3.(3)S&P’s lowest level of “investment grade” credit rating is BBB-.37Fitch’s, Moody’s and S&P’sbased on each rating outlooksagency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are stable for NVE, NPC and SPPC. A security rating is not a recommendation to buy, sell or hold securities. Securitysecurities, and there is no assurance that a particular credit rating will continue for any given period of time.subjecttied to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigningcredit ratings and accordingly, eachincrease or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.should be evaluatedagencies. These agreements may either specifically provide rights to demand cash or other security in the contextevent of a credit rating downgrade ("credit-risk-related contingent features") or provide the applicable methodology, independentlyright for counterparties to demand "adequate assurance," in the event of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.Energy Supplier MattersWith respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.Under these contracts, a material adverse change which includes ain creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2014, credit ratings from the three recognized credit rating downgrade of NPC and SPPC, may allow the counterparty to requestagencies were investment grade. If all credit-risk-related contingent features or adequate financial assurance which, if not provided within three business days, could cause a default. Most contracts and confirmationsprovisions for purchased power havethese agreements had been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market valuetriggered as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement2014, the Company would approximate a $94.6 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Gas Supplier MattersWith respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily mean a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of March 31, 2013, the maximum amount$56 million of additional collateral. The Company's collateral NPC would be requiredrequirements could fluctuate considerably due to post under these contractsmarket price volatility, changes in the eventcredit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. Financial Gas HedgesThe Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the 2012Company's collateral requirements specific to the Company's derivative contracts.NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities. Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities. If deemed prudent, the Utilities may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power. Cross Default ProvisionsNone of the Utilities’ financing agreements contains a cross default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in an event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other 38indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.RESULTS OF OPERATIONSNPC recognized net income of approximately $5.4 million during the three months ended March 31, 2013, compared to a net loss of approximately $1.3 million for the same period in 2012.For the periodyear ended MarchDecember 31, 2013, NPC paid $50.0 million in dividends to NVE. On May 8, 2013, NPC declared a dividend of $30.0 million to NVE.Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).The components of gross margin were (dollars in thousands):39Gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012. The increase is primarily due to $2.6 million related to a slight increase in the BTGR effective rate, a $2.3 million net increase in usage primarily due to milder weather in 2012 as indicated in the table below, and approximately $1.4 million due to customer growth.HDDs and CDDsMWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.The following table shows the HDDs and CDDswithin NPC’s service territory:The causes for2013. There have been no significant changes in specific lines comprising the resultsCompany's assumptions regarding critical accounting estimates since December 31, 2013.Quantitative and Qualitative Disclosures About Market Risk operations for NPCthe Company's Annual Report on Form 10-K for the respective periods are provided below (dollars in thousands except for amounts per unit):NPC’s retail revenues decreased for the three monthsyear ended MarchDecember 31, 2013, as compared2013. The Company's exposure to the same period in 2012 primarily duemarket risk and its management of such risk has not changed materially since December 31, 2013. Refer to $22.1 million in rate decreases largely due to NPC’s various BTER and DEAA quarterly updates (See Note 3, Regulatory Actions, 6 of the Notes to theConsolidated Financial Statements in the 2012Item 1 of this Form 10-K), and $7.7 million from decreases in EEPR rates effective January 1, 2013. Thesedecreases were offset by an increase of $6.5 million resulting from increased residential usage, primarily due to an increase in HDDs.40For the three months ended March 31, 2013, the average number of retail customers increased slightly by 0.6%, consisting of an increase in residential, commercial and industrial customers of 0.6%, 1.1% and 0.7%, respectively, compared to the same period in the prior year.Electric operating revenue – other10-Q for the three months ended March 31, 2013, compared to the same period in 2012, did not change materially. Energy CostsEnergy Costs include fuel for generation and purchased power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:•weather•generation efficiency•plant outages•total system demand•resource constraints•transmission constraints•natural gas constraints•long-term contracts•mandated power purchases; and•volatility of commodity pricesEnergy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power.•Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $13.5 million of the increase is due to an increase in natural gas prices and approximately $11.5 million of the increase is due to an increase in volume.Volume increased due to continued reliance on internal generation to satisfy load requirements. •Purchased power costs decreased slightly for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $65.5 million of the decrease was due to a decrease in volume. The decrease was largely offset by an increase of approximately $65.4 million in the cost of purchased power. As the volume of purchased power decreases, the remaining contracts consist primarily of higher cost renewable energy contracts and other long term fixed capacity contracts which are increasing the average cost per unit. Also contributing to the increase in the average cost per unit is the increase in the volume of power sales which are offset in purchased power. 41Deferred Energy for the three months ended March 31, 2013 include amortizations of $(27.3) million, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(18.0) million. Deferred Energy for the three months ended March 2012 include amortizations of previous over-collections of $(35.2) million, partially offset by over-collections of amounts recoverable in rates of $37.3 million. Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions,disclosure of the Condensed Notes to Financial Statements for further detail of deferred energy balances. For the three months ended March 31, 2013 energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.Other operating expense increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $2.7 million increase in stock compensation costs, offset by a $1.3 million decrease in telecommunications, meter reading and meter replacement software costs, and $0.7 million in lower pension and benefit costs.Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to $5.3 million in planned maintenance and outages at the Silverhawk, Higgins, Reid Gardner and Lenzie Generating Stations in 2012.Depreciation and amortization increased slightly for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service. Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012 due to a $2.2 million decrease in interest cost primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012 and an increase in AFUDC-debt of $0.7 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, due to a $1.6 million decrease in interest on deferred energy as a result of lower over-collected balances in 2013, and a decrease of $0.7 million in estimated interest expense accrued on the deferred gain on NPC’s wireless towers sold in 2011 pending final accounting approval by the PUCN in 2012, offset by $1.3 million net decrease of interest income due to lower regulatory asset balances. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K.42AFUDC-equity increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to various construction projects. Other income increased for the three months ended March 31, 2013, compared to the same period in 2012, by several items, all of which were immaterial. Other expense increased for the three months ended March 31, 2013, compared to the same period in 2012,by several items, all of which were immaterial. Analysis of Cash FlowsNPC’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, due to a decrease in cash from operating activities and an increase in cash used by investing and financing activities.Cash from Operating Activities - The decrease in cash from operating activities was primarily due to an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates, and reduced energy efficiency rates. These decreases were partially offset by increased cash flows from accounts receivable as a result of higher balances at December 31, 2012, compared to balances at December 31, 2011, due to higher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012. Further offsetting the decrease in cash from operating activities was the reduction in refunds to customers for previously over collected BTER balances. Cash used by Investing Activities - The increase in cash used by investing activities was primarily due to the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, related to the NV Energize project, partially offset by decreased construction activity related to the NV Energize project.Cash used by Financing Activities - Cash used by financing activities increased primarily due to an increase in dividends paid to NVE and a reduction in draws from the NPC revolving credit facility.LIQUIDITY AND CAPITAL RESOURCESOverall LiquidityNPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions. Available liquidityCompany's derivative positions as of March 31, 2013 was as follows (in millions):Available Liquidity as of March 31, 2013 (in millions)NPCCash and Cash Equivalents$132.2 Balance available on Revolving Credit Facility(1)497.3 $629.5 (1)As of May 7, 2013, NPC had approximately $497.3 million available under its revolving credit facility which includes reductions for letters of credits.NPC attempts to maintain its cashcash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending onProceduresusageend of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NPC is required to redeem approximately $98.1 millionperiod covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of May 8, 2013, NPC has no borrowings on its revolving credit facility, notCompany's management, including letters of credit. NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below). NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013. However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NPChas transitioned to slower growth, the amount of capital expenditures required has declined. NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to bettermanage and optimize its resources. As a result, NPC anticipates that they will be able to meet short-term operating costs and capital expenditures with internally generated fundsPresident (principal executive officer) and the use of its revolving credit facility. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.43However, if energy costs rise at a rapid rate or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Chief Financial Gas Hedges, the amount of liquidity available NPC could be significantly less. In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.During the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million. OnMay 8, 2013, NPC declared a dividend to NVE of $30.0 million.NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities. As discussed in Note 12, Commitments and ContingenciesOfficer (principal financial officer), of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR. The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC. During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.Factors Affecting LiquidityAbility to Issue DebtNPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, its revolving credit facility agreement, and the terms of certain NVE debt. As of March 31, 2013, the most restrictiveeffectiveness of the factors below is the PUCN authority. As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility. However, depending on NVE’s or SPPC’s issuance of long-term debt or the usedesign and operation of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:a.Financing authority from the PUCN - As of March 31, 2013, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. b.Financial covenants within NPC’s financing agreements – Under the NPC Credit Agreement, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00. Based on March 31, 2013 financial statements, NPC was in compliance with this covenant and could incur up to $2.8 billion of additional indebtedness.All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; andc.Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion. Ability to Issue General and Refunding Mortgage SecuritiesTo the extent that NPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the NPC Indenture.The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2013,$3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.6 billion of General and Refunding Mortgage Securities as of March 31, 2013. That amount is determined on the basis of:1.70% of net utility property additions; and/or2.the principal amount of retired General and Refunding Mortgage Securities.Property additions include plant in service. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.NPC also has the ability to release property from the lien of the NPC Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of the NPC Indenture, it will reduce the amount of securities issuable under the NPC Indenture.Credit RatingsThe liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt. On April 30, 2013, Fitch upgraded NPC’s corporate credit rating from BB+ to investment grade BBB-. NPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:Rating AgencyFitch(1)Moody’s(2)S&P(3)NPCSr. Secured Debt BBB+* Baa1* BBB+**Investment grade(1)Fitch’s lowest level of “investment grade” credit rating is BBB-.(2)Moody’s lowest level of “investment grade” credit rating is Baa3.(3)S&P’s lowest level of “investment grade” credit rating is BBB-.44Fitch’s, Moody’s and S&P’s rating outlooksare stable for NPC. A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.Energy Supplier MattersWith respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP agreement is posted on the WSPP website.Under these contracts, a material adverse change, which includes a credit rating downgrade, in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $94.6 million payment or obligation to NPC. These contracts qualify for the normal purchases and normal sales scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Gas Supplier MattersWith respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms, and as such, do not carry forward mark-to-market exposure. Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of March 31, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. Financial Gas HedgesNPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K, NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC. If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power. Cross Default ProvisionsNone of the financing agreements of NPC contains a cross default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.45Sierra Pacific Power CompanyRESULTS OF OPERATIONSSPPC recognized net income of $21.9 million for the three months ended March 31, 2013, compared to net income of $18.6 million for the same period in 2012. During the three months ended March 31, 2012, SPPC did not pay dividends to NVE. On May 8, 2013, SPPC declared a dividend of $20.0 million to NVE.Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).The components of gross margin were (dollars in thousands):Electric gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $1.2 million of the increase is due to customer growth and approximately $1.1 million of the increase is due to an increase in customer usage primarily due to an increase in HDDs as shown in the tables below. Gas gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012. The increase is primarily due to the increase in HDDs as shown in the tables below.HDDs and CDDsMWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.The following table shows the HDDs and CDDs within SPPC’s service territory:46The causes for significant changes in specific lines comprising the results of operations for SPPC for the respective periods are provided below (dollars in thousands except for amounts per unit):Retail revenue increased for the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to a $2.2 million increase in residential customer usage primarily due to an increase in HDDs as outlined in the table above, a $1.2 million increase in usage by mining customers and $0.7 million attributable to customer growth. These increases were partially offset by $1.8 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to Financial Statements) and $1.6 million of rate decreases due to various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements).For the three months ended March 31, 2013, the average number of residential, commercial and industrial customers increased 0.6%, 0.7% and 4.8%, respectively, compared to the same period in 2012.Electric operating revenues – Other increased by $1.5 million for the three months ended March 31, 2013, compared to the same period in 2012,primarily due to an increase in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).47SPPC’s retail gas revenues decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $9.7 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.7 million increase in customer usage primarily due to an increase in HDDs, as shown in the table above. Wholesale revenues increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in natural gas prices. Energy CostsEnergy Costs include purchased power and fuel for generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of purchased power versus fuel for generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:•weather•plant outages•total system demand•resource constraints•transmission constraints•gas transportation constraints•natural gas constraints•long-term contracts•mandated power purchases•generation efficiency; and•volatility of commodity pricesEnergy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to higher natural gas prices.Total MWhs increased for the three month period primarily due to an increase in HDDs.•Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $6.4 million of the change is due to higher natural gas prices partially offset by a decrease in volume of approximately $1.2 million.•Purchased power costs for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $3.1 million of the increase is due to increased reliance on purchased power along with a $1.2 million increase due to higher natural gas prices. Volume increased due to less reliance on internal generation.48Gas purchased for resale increased for the three months ended March 31, 2013,compared to the same period in 2012. Approximately $5.3 million of the increase is due to higher natural gas prices and approximately $0.7 million is due to an increase in volume. Deferred energy-electric for the three months ended March 31, 2013 include amortization of $(11.3) million which represent cash refunds to our customers for previous over-collections. Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(8.0) million. Deferred energy-electric for the three months ended March 31, 2012 include amortization of previous over-collections of $(25.5) million, partially offset by over-collections of amounts recoverable in rates of $12.8 million. Deferred energy-gas for the three months ended March 31, 2013 include amortizations of previous over-collections of ($13.4) million and under-collections of amounts recoverable in rates of $(0.9) million.Deferred energy-gas for the three months ended March 31, 2012 include amortization of previous over-collections of ($13.4) million, partially offset by over-collections of amounts recoverable in rates of $12.2 million.Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.For the three months ended March 31, 2013, energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.Other operating expensesdecreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to $1.0 million in lower telecommunications and software costs, and $0.6 million in lower pension and benefit costs. The decrease was partially offset by a $1.2 million increase in stock compensation costs.Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to a $1.4 million planned major outage at the Tracy Generating Station in 2012 and maintenance at the Valmy Generating Station in 2012 for $0.7 million.Depreciation and amortization increased slightlyfor the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.49Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.5 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $0.6 milliondecrease in interest on deferred energy as a result of lower over-collected balances in 2013, offset by a $0.4 million decrease in carrying charges on solar conservation programs. See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details of deferred energy balances.AFUDC-equity did not change materially for the three months ended March 31, 2013, compared to the same period in 2012. Other income decreased for the three months ended March 31, 2013, compared to same period in 2012, primarily due to the $1.1 million settlement with CAISO in 2011, recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.Other expense is comparable for the three months ended March 31, 2013, as compared to the same period in 2012.Analysis of Cash FlowsSPPC’s cash flows increased during the three months ended March 31, 2013, compared to the same period in 2012, due to an increase in cash from operating activities and a decrease in cash used by investing and financing activities.Cash from Operating Activities - The increase in cash from operating activities was primarily due to reduced coal and gas purchases, over collections of EEPR and reduction in refunds to customers for previously over collected BTER balances. Also contributing to the increase was the receipt of approximately $9.0 million in insurance proceeds related to a previous claim. These increases were partially offset by an under collection of energy costs in 2013, as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates. Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to decreased capital expenditure for the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.Cash used by Financing Activities - The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE.LIQUIDITY AND CAPITAL RESOURCESOverall LiquiditySPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions. Available liquidity as of March 31, 2013 was as follows (in millions):Available Liquidity as of March 31, 2013 (in millions)SPPCCash and Cash Equivalents$85.3 Balance available on Revolving Credit Facility(1)243.7 $329.0 (1)As of May 7, 2013, SPPC had approximately $243.7 million available under its revolving credit facility which includes reductions for letters of credits.50SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013. To meet this maturing debt obligation, SPPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of May 8, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below). In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2013. However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As SPPChas transitioned to slower growth, the amount of capital expenditures required has declined. SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources. As a result, SPPC anticipates that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility. Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.However, if energy costs rise at a rapid rate, or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from NVE.The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities. Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.During the three months ended March 31, 2013, SPPC did not pay dividends to NVE.On May 8, 2013 SPPC declared a dividend to NVE of $20.0 million.SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement, and maintenance of facilities.During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K.Factors Affecting LiquidityAbility to Issue DebtSPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. As of March 31, 2013, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:a.Financing authority from the PUCN - As of March 31, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350million; (2) to refinance up to approximately $598.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million;b.Financial covenants within SPPC’s financing agreements – Under the SPPC Credit Agreement, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00. Based on March 31, 2013 financial statements, SPPC was in compliance with this covenant and could incur up to $1.1 billion of additional indebtedness;All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; andc.Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion.51 Ability to Issue General and Refunding Mortgage SecuritiesTo the extent that SPPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the SPPC Indenture.The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of March 31, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $824 millionof additional General and Refunding Mortgage Securities as of March 31, 2013. That amount is determined on the basis of:1.70% of net utility property additions; and/or2.the principal amount of retired General and Refunding Mortgage Securities.Property additions include plant in service. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.SPPC also has the ability to release property from the lien of the SPPC Indenture on the basis of net property additions, cash, and/or retired bonds. To the extent SPPC releases property from the lien of the SPPC Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.Credit RatingsThe liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt. On April 30, 2013, Fitch upgraded SPPC’s corporate credit rating from BB+ to investment grade BBB-. SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:Rating AgencyFitch(1)Moody’s(2)S&P(3)SPPCSr. Secured Debt BBB+* Baa1* BBB+**Investment grade(1)Fitch’s lowest level of “investment grade” credit rating is BBB-.(2)Moody’s lowest level of “investment grade” credit rating is Baa3.(3)S&P’s lowest level of “investment grade” credit rating is BBB-.Fitch’s, Moody’s and S&P’s rating outlooksare stable for SPPC. A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.Energy Supplier MattersWith respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.Under these contracts, a material adverse change, which includes a credit rating downgrade in SPPC may allow the counterparty to request adequate financial assurance, which if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. According to the net mark-to-market value as of March 31, 2013, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement. These contracts qualify for the normal purchases and normal sales scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. 52Gas Supplier MattersWith respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery. Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which under certain circumstances require the Utilities to provide collateral to continue receiving service.Financial Gas HedgesSPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K, SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC. If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.Cross Default ProvisionsNone of the financing agreements of SPPC contains a crossdefault provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.RECENT PRONOUNCEMENTSSee Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements, and Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKInterest Rate RiskAs of March 31, 2013, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):53Commodity Price RiskSee the 2012 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2012.Credit RiskThe Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $98.6 million as of March 31, 2013, which compares to balances of $77.5 million at December 31, 2012. The increase from December 31, 2012 is primarily due to the increase in forward prices of power and natural gas during the first quarter of 2013.ITEM 4.CONTROLS AND PROCEDURES (a)Evaluation of disclosure controls and procedures. NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’Company's disclosure controls and procedures (as defined in RulesRule 13a-15(e) and 15d-15(e) ofpromulgated under the Securities and Exchange Act of 1934) have1934, as amended). Based upon that evaluation, the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that as of March 31, 2013, the registrants’Company's disclosure controls and procedures were effective.(b)Change in internal controls over financial reporting.There were no changeseffective to ensure that information required to be disclosed by the Company in the registrants’reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to management, including the Company's President (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company's internal controlscontrol over financial reporting induring the first quarter of 2013ended March 31, 2014 that havehas materially affected, or areis reasonably likely to materially affect, the registrants’Company's internal controlscontrol over financial reporting.54 - OTHER INFORMATIONITEM 1. LEGAL PROCEEDINGSLegal Proceedings Other Legal MattersNVE and its subsidiaries, throughRisk Factors course of their normal business operations, are currently involved in a number of other legal actions, none of which has had, or in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 7, Commitments and Contingencies, of the Condensed Notes to Financial Statements for further discussion of other legal matters.For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the informationCompany's risk factors from those disclosed in Item 1A “Risk Factors,” of our 2012 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.As of the dateCompany's Annual Report on Form 10-K for the year ended December 31, 2013.Unregistered Sales of Equity Securities and Use of Proceeds Defaults Upon Senior Securities Mine Safety Disclosures Other Information Exhibits report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2012 Form 10-K.ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDSIssuer Purchases of Equity SecuritiesThe following table contains information about NVE’s purchases of common stock for the quarter ended March 31, 2013:ITEM 3.DEFAULTS UPON SENIOR SECURITIESNone.ITEM 4.MINE SAFETY DISCLOSURESNot applicable.None. 55(a)Exhibits filed with this Form 10-Q:(10) NV Energy, Inc.:10.1Form of Performance Shares Agreement for 2013 Awards.10.2Form of Restricted Stock Unit Agreement for 2013 Awards.(12) NV Energy, Inc.:12.1Statement regarding computation of Ratios of Earnings to Fixed Charges. Nevada Power Company:12.2Statement regarding computation of Ratios of Earnings to Fixed Charges. Sierra Pacific Power Company:12.3Statement regarding computation of Ratios of Earnings to Fixed Charges.(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company31.1Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.3Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.4Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.5Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.6Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company32.1Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.3Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.4Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.5Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.6Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(101) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company101.INSXBRL Instance Document101.SCHXBRL Taxonomy Schema101.CALXBRL Calculation Linkbase101.LABXBRL Label Linkbase101.PREXBRL Presentation Linkbase101.DEFXBRL Definition Linkbase56SIGNATURESregistrants haveregistrant has duly caused this report to be signed on theirits behalf by the undersigned thereunto duly authorized.NV Energy, Inc. (Registrant)(Registrant) Date:May 8, 2013By:/s/ Jonathan S. HalkyardJonathan S. HalkyardChief Financial Officer(Principal Financial Officer)8, 2013By:Chief Accounting Officer(Principal Accounting Officer)Nevada Power Company d/b/a NV Energy (Registrant)Date: May 8, 2013By:/s/ Jonathan S. HalkyardJonathan S. Halkyard(principal financial and accounting officer) Exhibit No. Description (15 Awareness Letter of Independent Registered Public Accounting Firm. 31.1 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Principal Financial Officer)Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Date: May 8, 2013Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. By:/s/ E. Kevin Bethel101 E. Kevin BethelChief Accounting Officer(Principal Accounting Officer)Sierra PacificThe following financial information from Nevada Power Company d/b/a NV Energy (Registrant)Date: May 8, 2013By:/s/ Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014Jonathan S. HalkyardJonathan S. HalkyardChief, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholder's Equity, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Officer(Principal Financial Officer)Date: Statements, tagged in summary and detail.May 8, 2013By:/s/ E. Kevin BethelE. Kevin BethelChief Accounting Officer(Principal Accounting Officer)57