Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

All shares of outstanding common stock of Nevada Power Company are held by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of July 31, 2014,2015, 1,000 shares of common stock, $1.00 stated value, were outstanding.

When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following terms have the definitions indicated.

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the Company's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of the Company and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:

Further details of the potential risks and uncertainties affecting the Company are described in the Company'sits filings with the United States Securities and Exchange Commission, including Part II, Item 1A and other discussions contained in this Form 10‑Q. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.

To the Board of Directors and Shareholder of

Nevada Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries (the "Company") as of June 30, 2014,2015, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 20142015 and 2013,2014, and of changes in shareholder's equity and cash flows for the six-month periods ended June 30, 20142015 and 2013.2014. These interim financial statements are the responsibility of the Company's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2013,2014, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated March 31, 2014,February 27, 2015, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 20132014 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

Nevada Power Company, together with its subsidiaries (collectively, the "Company"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States regulated electric 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 Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in 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 unaudited Consolidated Financial Statements as of June 30, 20142015 and for the three- and six-month periods ended June 30, 20142015 and 2013. Certain amounts in the prior periods Consolidated Statement of Operations have been reclassified to conform to the current period's presentation. Such reclassifications did not impact previously reported net income.2014. The results of operations for the three- and six-month periods ended June 30, 20142015 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 20132014 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 six-month period ended June 30, 2014.2015.

In May 2014,April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09,2015-03, which createsamends FASB Accounting Standards Codification ("ASC") Subtopic 835-30, "Interest - Imputation of Interest." The amendments in this guidance require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability instead of as an asset. This guidance is effective for interim and annual reporting periods beginning after December 15, 2015, with early adoption permitted. This guidance must be adopted retrospectively, wherein the balance sheet of each period presented should be adjusted to reflect the new guidance. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. This guidance isIn July 2015, the FASB decided to defer the effective fordate one year to interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted.2017. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

The PUCN's final order approving the merger between BHE and NV EnergyMerger stipulated that the Company willwould not seek recovery of any lost revenue for calendar year 2014 in an amount that exceedsexceeded 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to reset the EEIR and energy efficiency implementation rate.program rates. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate,EEIR, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The energy efficiency implementation rate will beEEIR was effective from July through December 2014, and will reset on January 1, 2015 and remainremains in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to set base general rates, the Company is required to refund to customers energy efficiency implementation rateEEIR revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rateEEIR revenue collected and has recorded a liability of $7$14 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of June 30, 2014.2015.

In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requestsrequested incremental annual revenue relief in the amount of $38 million, or an average price increase of 2%. AnIn October 2014, the Company reached a settlement agreement with certain parties agreeing to a zero increase in the revenue requirement. In October 2014, the PUCN issued an order is expected byin the end of 2014 and, if approved,general rate case filing that accepted the new rates would besettlement. The order provides for increases in the fixed-monthly service charge for customers with a corresponding decrease in the base tariff general rate effective January 1, 2015. As a result of the order, the Company recorded $15 million in asset impairments related to property, plant and equipment and $5 million of regulatory asset impairments, which are included in operating and maintenance on the Consolidated Statements of Operations for the year ended December 31, 2014. Additionally, the Company recorded a $5 million gain in other, net on the Consolidated Statement of Operations for the year ended December 31, 2014 related to the disposition of property. In October 2014, a party filed a petition for reconsideration of the PUCN order. In November 2014, the PUCN granted the petition for reconsideration and reaffirmed the order issued in October 2014.

In May 2013, the Company, along with Sierra Pacific, filed an application with the FERC to establish single system transmission and ancillary service rates. The combined filing requested incremental rate relief of $17 million annually to be effective January 1, 2014. OnIn August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to refund, and set the case 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 the FERC's order. As of June 30,

In September 2014, the Company, accrued $7 millionalong with Sierra Pacific, filed an unopposed settlement offer with the FERC on behalf of NV Energy and the intervening parties providing rate relief of $4 million. The settlement offer would resolve all outstanding issues related to this case. In addition, a preliminary order from the administrative law judge granting the motion for amounts subject tointerim rate refund,relief was issued, 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.

The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non-Qualified"Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the Company. Amounts attributable to the Company were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive income.loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):

The Company is exposed to the impact of market fluctuations in commodity prices and interest rates. The Company is principally exposed to electricity, natural gas and coal and other commodity price risk as it has anmarket fluctuations primarily through the Company's obligation to serve retail customer load in its regulated 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 areis 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.

The Company has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-ratefixed‑rate long-term debt and by monitoring market changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 87 for additional information on derivative contracts.

The following table, which excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):

The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values as of (in millions):

The Company extends unsecuredis exposed to counterparty credit torisk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations.participants. Credit risk may be concentrated to the extent that one or more groups ofthe Company's counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may defaultand due to circumstances relating directly to it, but alsodirect and indirect

relationships among the risk thatcounterparties. Before entering into a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship withtransaction, the counterparty.

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2014,2015, credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features was $5 million and $4 million as of June 30, 2015 and December 31, 2014, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

The carrying value of the Company's cash, certain cash equivalents, receivables, investments held in Rabbi trusts, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels 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:

The following table presents the Company's commodityassets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are valued usingnot available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market approachprice quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses quotedforward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, for similar assetsrelated volatility, counterparty creditworthiness and liabilities, whichduration of the contracts. The model incorporates a mid-market pricing convention (the mid-pointmid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instrumentscontracts not only includes counterparty risk, but also the impact of the Company's nonperformance risk on its liabilities, which as of June 30, 20142015 and December 31, 2013,2014, had an immaterial impact to the fair value of its derivative instruments.contracts. As such, the Company considers its commodity derivative contracts to be valued using Level 3 inputs. Refer to Note 6 for further discussion regarding the Company's risk management and hedging activities.

The following table reconciles the beginning and ending balances of the Company's commodity derivative liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):

The Company's long-term debt is carried at cost on the Consolidated Financial Statements.Balance Sheets. The fair value of the Company's long-termlong‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value 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-termlong‑term debt (in millions):

The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

In February 2014, the PUCN issued a final order approving draft regulations, subject to review by a Nevada Legislative commission and which must be filed with the Secretary of State, and the regulations became effective March 2014. In May 2014, the Company filed its EmissionEmissions Reduction Capacity Replacement Plan proposing,("ERCR Plan") in compliance with SB 123 enacted by the 2013 Nevada Legislature. The filing proposed, among other items, the retirement of Reid Gardner Generating Station 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 generationgenerating capacity being retired, as required by Senate Bill No.SB 123. The Emissions Reduction and Capacity ReplacementERCR Plan includes the issuance of requests for proposals for 300 MW300-MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 274-MW272‑MW natural gas co-generating facility in 2014; the acquisition of a 222-MW210-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 ReplacementERCR Plan, which are subject to the PUCN approval. The PUCN has scheduled a hearing on the application beginning in September 2014 andissued an order is expecteddated October 28, 2014 removing the 200-MW solar photovoltaic facility proposed by the Company from the ERCR Plan but accepting the remaining requests. In November 2014, the Company filed a petition for reconsideration, but in December 2014, the PUCN upheld the original order from October 2014 with respect to material matters. In December 2014, the Company filed its acceptance of the modifications to the ERCR Plan.

In July 2015, the Company filed an amendment to its ERCR Plan with the PUCN. The amendment requests PUCN approval of two renewable power purchase agreements with 100‑MW solar photovoltaic generating facilities related to the replacement of coal plants. Each of these agreements were entered into by issuing requests for proposals for the procurement of energy through the competitive solicitation process that was set forth in the fourth quarterCompany's ERCR Plan in compliance with SB 123. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of 2014.SB 123. As a result, the Company will not proceed with issuance of a third 100-MW request for proposal for renewable energy until such time as the PUCN determines the Company has satisfactorily demonstrated a need for such electric generating capacity.

In October 2011, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Reid Gardner Generating Station located near Moapa, Nevada. The Environmental 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 Environmental Protection Agency relating to the plant. The Company completed its responses to the Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this information request.

The Company is party to a variety of legal actions arising out of the normal course of business. 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 legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

In 2006, November 2005 Land Investors, LLC ("NLI") purchased from the United States through the Bureau of Land Management 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land is traversed by a 500 kilovolt ("kV") transmission line owned by the Company and sited pursuant to a pre-existing right-of-way grant from the Bureau of Land Management. Subsequent to NLI's purchase, a dispute arose as to whether the Company owed rent and, if it did, the amount 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 contract, inverse condemnation and trespass. The Company counterclaimed for express condemnation of a perpetual easement over the right-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 right-of-way corridor. The Company has posted the required bond of $6$12 million and has subsequently appealed to the Nevada Supreme Court. Management cannot assess or predictIn June 2015, the outcomeparties finalized a settlement in this matter, separate from the court order above, and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

The Company has six other rights-of-way located on the same 2,675 acres of land located in North Las Vegas, Nevada, commonly referred to as the Park Highlands properties. NLI purportedly also terminated the other six rights‑of‑way. On January 2, 2015, KBS SOR Park Highlands, LLC ("KBS") filed a complaint in the Eighth District Court relating to one of the casesix rights‑of‑way, specifically the right-of-way that relates to a 230‑kV line that traverses the property. In the complaint, KBS raised the same claims previously raised by NLI in the litigation relating to the 500‑kV line. On January 9, 2015, the Company filed an action in the Eighth District Court relating to the six rights-of-way on the Park Highlands properties. This action sought a declaratory order quieting the Company's title to the rights-of-way or in the alternative condemning an easement interest in the property. In June 2015, the parties finalized a settlement in this matter and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

In 2005, the Bureau of Land Management sold at auction a parcel of land commonly known as the Skye Canyon properties. The property was sold subject to preexisting rights-of-way held by the Company for the placement of electric transmission and distribution facilities. On January 9, 2015, the Company filed an action in the Eighth District Court relating to 14 rights‑of‑way located within the Skye Canyon properties. The action sought a declaratory order from the court that the rights-of-way held by the Company are still valid, establish the proper rent, if any, payable by the Company and to identify the proper party to whom rent is due. In June 2015, the parties finalized a settlement in this time.matter and final documents dismissing the claims have been filed with the Eighth District Court. The settlement did not have a material impact to the Company's Consolidated Financial Statements.

In August 2013, the Sierra Club and Moapa Band of Paiute Indians filed a complaint in federal district court in Nevada against the Company and the California Department of Water Resources, alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to the environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the Resource Conservation and Recovery Act. The complaint also alleges that the Reid Gardner Generating Station is engaged in the unlawful discharge of pollutants in violation of the Clean Water Act. The notice was issued pursuant to the citizen suit provisions of the Resource Conservation and Recovery Act and the Clean Water Act. CDWRThe California Department of Water Resources was named as a co-defendant in the litigation due to its prior co-ownership in Reid Gardner Generating Station unitUnit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. In August 2014, the court dismissed without prejudice the plaintiff's amended complaint which sought civil penalties. In June 2015, the parties reached a settlement in principle in this matter. The Company answered the complaint and intends to vigorously defend the suit. Given the stage of the proceeding, management cannot predict thesettlement will not have a material impact to the Company, or estimate the range of loss.Company's Consolidated Financial Statements.

The 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. The Company is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. 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 short- and long-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 Company. Additionally, the timely recovery of purchased power, 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 Company.

The following is management's discussion and analysis of 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.

Net income for the second quarter of 20142015 was $62$60 million, an increasea decrease of $3$2 million, or 5%3%, as compared to 2014 due to ON Line lease expense, which was deferred in 2014 but expensed in 2015, lower margins from decreased customer usage, and higher depreciation and amortization costs, partially offset by lower debt interest expense and customer growth.

Net income for the first six months of 20142015 was $68$84 million, an increase of $4$16 million, or 6%24%, as compared to 2013.2014 due to lower debt interest expense, higher margins from increased customer growth and a rate design change from the 2014 rate case effective January 2015, changes in contingent liabilities and the gain on sale of an equity investment. These increases were partially offset by ON Line lease expense, which was deferred in 2014 but expensed in 2015, and higher depreciation and amortization costs.

Operating revenue and cost of fuel, energy and capacity are key drivers of the Company's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. The Company believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful. A comparison of the Company's key operating results is as follows:

As of June 30, 2014,2015, the Company's total net liquidity was $568$506 million consisting of $168$106 million in cash and cash equivalents and $400 million of revolving credit facility availability.

Net cash flows from operating activities for the six-month periods ended June 30, 2015 and 2014 and 2013 were $148$257 million and $130$148 million, respectively. The change was primarily due to reducedan increase in collections for deferred energy costs, higher revenue collections as a result of a change in rate design and one-time bill credit of $15 million to retail customers refunded in 2014 in connection with the BHE Merger. The increase was partially offset by higher refunds to customers for previously over-collected deferred energy costs, increased transmission salesconservation and timingrenewable programs, settlement payments of short-term incentive payments, partially offset by a one-time bill credit paid to retail customers in 2014 associated with the merger between BHEcontingent liabilities and NV Energy, increased spending on renewable energy programs and increased rent payments related to the ON Line transmission use agreement.lower collections of demand side management programs.

Net cash flows from investing activities for the six-month periods ended June 30, 2015 and 2014 and 2013 were $(97)$(106) million and $(107)$(97) million, respectively. The change was primarily due to an increase in contributions in aid of construction and customer advances,capital expenditures, partially offset by the cash received from the sale of assets and an increase in capital expenditures.equity investment.

Net cash flows from financing activities for the six-month periods ended June 30, 2015 and 2014 and 2013 were $(9)$(265) million and $(82)$(9) million, respectively. The change was primarily due to a decrease inrepayments of long-term debt and dividends partially offset by debt tendered in 2014 as a resultpaid to NV Energy.

In January 2015, the Company repaid the aggregate principal amount outstanding of $250 million 5.875% Series L General and Refunding Mortgage Notes at 100% of the merger between BHEprincipal amount plus accrued interest with the use of cash on hand and NV Energy and capital lease payments.short-term borrowings. The short-term borrowings were repaid in June 2015.

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of June 30, 2014,2015, the Company has financing authority from the PUCN consisting of authoritythe ability to: (1) issue additional long-term debt securities of up to $725 million; (2) refinance up to $423$553 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of June 30, 2014.2015. In addition, certain financing agreements contain covenants which are currently suspended as the Company's senior secured debt is rated investment grade. However, if the Company's senior secured debt ratings fall below investment grade by either Moody's InvestorInvestors Service or Standard & Poor's, the Company would be subject to limitations under these covenants.

The Company has available a variety of sources of liquidity and 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 availability 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.

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-controlpollution control technologies, replacement generation and associated operating costs are generally incorporated into the Company's regulated retail rates. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are approximately $383 million for the year ended December 31, 2014 and are as follows (in millions):

As of June 30, 2014,2015, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.2014.

The Company is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013,2014, and new regulatory matters occurring in 2014.2015.

The PUCN's final order approving the merger between BHE and NV EnergyMerger stipulated that the Company willwould not seek recovery of any lost revenue for calendar year 2014 in an amount that exceedsexceeded 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to reset the EEIR and energy efficiency implementation rate.program rates. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate,EEIR, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The energy efficiency implementation rate will beEEIR was effective from July through December 2014, and will reset on January 1, 2015 and remainremains in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to set base general rates, the Company is required to refund to customers energy efficiency implementation rateEEIR revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rateEEIR revenue collected and has recorded a liability of $7$14 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of June 30, 2014.2015.

In July 2015, the Company filed an amendment to its ERCR Plan with the Emissions Reduction Capacity ReplacementPUCN. The amendment requests PUCN approval of two renewable power purchase agreements with 100‑MW solar photovoltaic generating facilities related to the replacement of coal plants. Each of these agreements were entered into by issuing requests for proposals for the procurement of energy through the competitive solicitation process that was set forth in the Company's ERCR Plan in compliance with Senate Bill No. 123 ("SB 123") enacted by. In June 2015, the 2013 Nevada Legislature. State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123. As a result, the Company will not proceed with issuance of a third 100-MW request for proposal for renewable energy until such time as the PUCN determines the Company has satisfactorily demonstrated a need for such electric generating capacity.

The filing proposed, among other items,Company and Sierra Pacific are currently parties to an Interim Joint Dispatch Agreement ("Interim JDA") which outlines the retirementjoint dispatch of Reid Gardner Generating Station units 1, 2their combined power supply resources utilizing ON Line. In March 2015, the Company and 3 in 2014 and unit 4 in 2017;Sierra Pacific filed an application with the eliminationPUCN seeking approval of the Company's ownership interest in Navajo Generating Station in 2019; and a planan indefinite Joint Dispatch Agreement ("JDA"). The JDA is intended to replace the generation capacity being retired, as requiredcurrently effective Interim JDA, which terminates on December 31, 2015. Joint dispatch transactions addressed by SB 123.the proposed JDA include real-time, hourly and daily transactions. The Emissions ReductionJDA also explicitly governs joint dispatch transactions between the Company 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;Sierra Pacific and the construction of a 200-MW solar photovoltaic facility expectedCalifornia ISO utilizing the California ISO's EIM.

The primary differences between the Interim JDA and the JDA relate to be placed in-service in 2016. InEIM transactions with the second quarter of 2014,California ISO. The JDA establishes the Company executed various contractual agreements to fulfillas the proposed Emissions ReductionEIM scheduling coordinator for both the Company and Capacity Replacement Plan,Sierra Pacific and recognizes that the joint dispatch costs and benefits associated with EIM transactions will be governed by the accounting protocols and allocations set forth in the JDA, which are subject tounchanged from those currently in effect under the Interim JDA. In July 2015, the PUCN approval. The impacts ofapproved the Emissions Reduction Capacity Replacement Plan toJDA with minor modifications, and established December 31, 2019 as the Company's 2014 forecasted capital expenditures are included intermination date for the Future Uses of Cash previously discussed. The PUCN has scheduled a hearing onagreement. In July 2015, the application beginning in September 2014 and an order is expected inJDA was filed with the fourth quarter of 2014.FERC for approval.

In MayOctober 2014, the PUCN issued an order directing the Company to provide information relating to failures in certain remote disconnect/reconnect electric meters the Company has installed after media reports were published that electric meter failures may have resulted in fire events. The Company completed an internal review in response to this and other federal, state and local inquiries relating to these events. The information compiled and submitted indicates that no fire has resulted from the remote disconnect/reconnect electric meters. Additionally, in October 2014, the Nevada State Fire Marshal issued a report concluding that the incidents of electric arcing fires continue to decrease in Nevada and at this time there is no statewide fire problem related to the replacement of electric meters. In December 2014, the Company filed a general rate casethe requested information with the PUCN. In July 2014,March 2015, the PUCN staff made additional requests and in May 2015, the Company made its certification filing, whichprovided the follow up items and has not received any additional requests incremental annual revenue relief inpertaining to this item. Analysis and internal investigation is continuing, but the amount of $38 million or an average price increase of 2%. An order is expected byCompany does not believe this will have a material adverse impact on the end of 2014 and, if approved, the new rates would be effective January 1, 2015.Consolidated Financial Statements.

The Company and Sierra Pacific have announced plans to join the energy imbalance market ("EIM")EIM in October 2015. The EIM is expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of generation resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In today's environment, utilitiesJuly 2015, following the issuance of an order by the FERC and in the west outsideconjunction with the California Independent System Operator ("California ISO") rely uponISO's announcement of a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply and have limited capability to transact within the hour outside their own borders. In contrast, the EIM will optimize and automate five-minute dispatch of generation to serve load across the state andsupplemental stakeholder process, the California ISO footprint. The EIM is voluntary and available to all balancing authorities in the Western United States. Benefits to customers are expected to increase as more entities join and the footprint grows bringing incremental generation and load diversity. In April 2014, the Company filed an application to amend its portfolio optimization procedures contained in the PUCN-approved energy supply plan for the remaining action period of 2015. The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company would obtain PUCN authorization prior to participating in an EIM. The amendment reflects the Company's participationannounced a change in the EIM that is being established by the California ISO.

The Company is subject to federal, state local and foreignlocal laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state local and internationallocal agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecastedforecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.2014.

The Clean Air Act isSierra Club filed a federal law administeredlawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2020 sulfur dioxide standard, and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations and supporting information by the specified deadline of September 18, 2015. The EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"), which are a collection of regulations, programs and policiesintends to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirementspromulgate final sulfur dioxide area designations no later than those implemented by the EPA.July 2, 2016.

The Clean Air Mercury Rule ("CAMR"), issued by the EPANumerous lawsuits have been filed in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011,challenging the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, Mercury and Air Toxics Standards ("MATS"), was published in the Federal Register in February 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards by April 16, 2015. Individual sources may be granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators, are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards, which may include retiring certain units.

In June 2014, the EPA released proposed regulations to address greenhouse gasGHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on four building blocks that it determined were the "Best System of Emission Reduction." The four building blocks include: (a) a 6% heat rate improvement from coal-fueled generating facilities; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities to 70%; (c) increased deployment of renewable and non-carbon generating resources; and (d) increased energy efficiency. Under the EPA'sthis proposal, Nevada may utilizestates could have utilized any measure to achieve the specified emission reduction goals, with an initial implementation period of 2020-2029 and the final goal to be achieved by 2030. When fully implemented, the proposal iswas expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The final Clean Power Plan was released August 3, 2015 and changed the methodology upon which the Best System of Emission Reduction is based to include: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is takingexpected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. The EPA also released on August 3, 2015, a draft federal plan as an option or backstop for states to utilize in the event they do not submit approvable state plans. The draft federal plan is expected to be open for a 90-day public comment on its proposal until October 16, 2014 and is scheduled to issue final rulesperiod after publication in June 2015.the Federal Register. States are required to submit initial implementation plans by JuneSeptember 2016, but theyand may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program.September 2018. The impacts of the proposalfinal rule or the federal plan on the Company cannot be determined until the EPA finalizes the proposal and Nevadastate develops its implementation plan.plan or the federal plan is finalized. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of itstheir generating fleetfleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

The federal Water Pollution ControlGHG rules and the Company's compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the Resource Conservation and Recovery Act ("Clean Water Act"RCRA") establishes. The public comment period closed in November 2010. The final rule was released by the framework for maintaining and improving water qualityEPA on December 19, 2014, was published in the United States through a program thatFederal Register on April 17, 2015 and will be effective on October 19, 2015. The final rule regulates among other things, discharges tocoal combustion byproducts as non-hazardous waste under RCRA Subtitle D and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performanceestablishes minimum nationwide standards for existing electricity generating facilitiesthe disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements.

As defined by the final rule, the Company operates ten evaporative surface impoundments and one landfill that take in more than 50 million gallons of water per day. These rules were aimed at minimizingcontains coal combustion byproducts. The Company has assessed the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms loston asset retirement obligations as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit ("Second Circuit") remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.

Debt of the Company is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

The Company has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase 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.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security in the event ofif credit exposures on a credit rating downgradenet basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2014,2015, the applicable credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of June 30, 2014,2015, the Company would have been required to post $69$74 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of the Company's collateral requirements specific to the Company's derivative contracts.

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K10‑K for the year ended December 31, 2013.2014. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2013.2014.

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.2014. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, 2013.2014. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q10‑Q for disclosure of the Company's derivative positions as of June 30, 2014.2015.

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, 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 the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the 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 control over financial reporting during the quarter ended June 30, 20142015 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

None.

There has been no material change to the Company's risk factors from those disclosed in Item 1A of the Company's Annual Report on Form 10-K10‑K for the year ended December 31, 2013.2014.

Not applicable.

Not applicable.

None.

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

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