News Column

NEVADA POWER CO - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 1, 2014

General

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.



Results of Operations for the Second Quarter and First Six Months of 2014 and 2013

Net income for second quarter of 2014 was $62 million, an increase of $3 million, or 5%, and for the first six months of 2014 was $68 million, an increase of $4 million, or 6%, as compared to 2013. 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: Second Quarter First Six Months 2014 2013 Change 2014 2013 Change Gross margin (in millions): Operating revenue $ 595$ 536$ 59 11 % $ 1,012$ 906$ 106 12 % Cost of fuel, energy and capacity 284 209 75 36 487 351 136 39 Gross margin $ 311$ 327$ (16 ) (5 ) $ 525$ 555$ (30 ) (5 ) Sales (GWh): Residential 2,296 2,354 (58 ) (2 ) % 3,761 3,965 (204 ) (5 ) % Commercial 1,180 1,179 1 - 2,113 2,095 18 1 Industrial 2,013 2,042 (29 ) (1 ) 3,642 3,677 (35 ) (1 ) Other 46 49 (3 ) (6 ) 98 97 1 1 Total retail 5,535 5,624 (89 ) (2 ) 9,614 9,834 (220 ) (2 ) Wholesale 1 5 (4 ) (80 ) 6 18 (12 ) (67 ) Total sales 5,536 5,629 (93 ) (2 ) 9,620 9,852 (232 ) (2 ) Average number of retail customers (in thousands) 873 859 14 2 % 871 855 16 2 % Average retail revenue per MWh $ 105.54$ 93.79$ 11.75 13 % $ 103.39$ 90.74$ 12.65 14 % Heating degree days 41 34 7 21 % 709 1,084 (375 ) (35 ) % Cooling degree days 1,365 1,408 (43 ) (3 ) 1,399 1,494 (95 ) (6 ) Sources of energy (GWh): Coal 1,351 794 557 70 % 2,577 1,267 1,310 103 % Natural gas 3,012 3,734 (722 ) (19 ) 5,281 7,128 (1,847 ) (26 ) Total energy generated 4,363 4,528 (165 ) (4 ) 7,858 8,395 (537 ) (6 ) Energy purchased 1,542 1,505 37 2 2,353 2,148 205 10 Total 5,905 6,033 (128 ) (2 ) 10,211 10,543 (332 ) (3 ) 13

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Gross margin decreased $16 million, or 5%, for the second quarter of 2014 compared to 2013 due to: • $8 million in lower usage primarily due to a decrease in cooling degree days;

• $7 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense;



• $4 million in lower volume driven demand charges to industrial customers

due to lower cooling degree days; and

• $3 million in lower energy efficiency implementation rate revenue.

The decrease in gross margin was partially offset by: • $4 million higher transmission rate revenue; and

• $3 million due to customer growth.

Gross margin decreased $30 million, or 5%, for the first six months of 2014 compared to 2013 due to: • $20 million in lower usage primarily due to a decrease in cooling degree

days during 2014; • $12 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense;



• $6 million in lower energy efficiency implementation rate revenue; and

• $3 million in lower volume driven demand charges to industrial customers

due to lower cooling degree days.

The decrease in gross margin was partially offset by: • $6 million in higher transmission rate revenue; and

• $5 million due to customer growth.

Operating and maintenance expense decreased $17 million, or 16%, for the second quarter of 2014 compared to 2013 due to: • $7 million in lower energy efficiency program costs, which are fully recovered in operating revenue;



• $3 million in decreased major outages and planned maintenance expense at

the Higgins, Silverhawk and Harry Allen Generating Stations;

• $3 million in lower compensation costs;

• $3 million in lower investor relation, bad debt and insurance costs; and

• $2 million in lower sales taxes related to a long-term service agreement

settlement.

The decrease in operating and maintenance expense was partially offset by higher operating costs for Reid Gardner Unit 4 of $2 million previously shared with the former partner. Operating and maintenance expense decreased $34 million, or 17%, for the first six months of 2014 compared to 2013 due to: • $12 million in lower energy efficiency program costs, which are fully recovered in operating revenue;



• $9 million in decreased major outages and planned maintenance expense at

the Higgins, Lenzie, Silverhawk and Harry Allen Generating Stations;

• $8 million in lower compensation, employee benefits and stock compensation

costs;

• $6 million in lower investor relation, bad debt and insurance costs;

• $2 million in lower costs associated with outside consulting services; and

• $2 million in lower sales taxes related to a long-term service agreement

settlement.

The decrease in operating and maintenance expense was partially offset by: • $3 million in higher operating costs for Reid Gardner Unit 4 previously

shared with the former partner; and

• $2 million in ON Line lease payments.

Depreciation and amortization increased $4 million, or 6%, for the second quarter and $5 million, or 4%, for the first six months of 2014 compared to 2013 primarily due to higher plant-in-service, including ON Line being placed in-service in December 2013.

14 -------------------------------------------------------------------------------- Merger-related expense decreased $9 million for both the second quarter and for the first six months of 2014 compared to 2013 due to costs incurred related to the merger of BHE and NV Energy in 2013. Interest expense, net of allowance for debt funds decreased $1 million, or 2%, for the second quarter and $3 million, or 3%, for the first six months of 2014 compared to 2013 as a result of using cash on hand to repay existing debt in July and December 2013 and lower amortization of debt expenses of $1 million for both the second quarter and the first six months of 2014 compared to 2013, partially offset by lower debt AFUDC of $2 million for the second quarter and $3 million for the first six months of 2014 compared to 2013 due to lower construction activity.



Allowance for equity funds decreased $2 million for the second quarter and $4 million for the first six months of 2014 compared to 2013 due to assets placed in-service, including ON Line being placed in-service in December 2013, and a decrease in construction activity.

Other, net increased $1 million, or 33%, for the second quarter and $2 million, or 25%, for the first six months of 2014 compared to 2013 due to $1 million in higher dividend and investment income in the second quarter of 2014 and $1 million in higher interest earned on regulatory items for the first six months of 2014. Income tax expense increased $3 million, or 9%, for the second quarter and $4 million, or 11%, for the first six months of 2014 compared to 2013 and the effective tax rates were 36% for the second quarter and first six months of 2014 and 35% for the second quarter and first six months of 2013. The increase in income tax expense is primarily due to higher income before income tax expense.



Liquidity and Capital Resources

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

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2014 and 2013 were $148 million and $130 million, respectively. The change was primarily due to reduced refunds to customers for previously over-collected deferred energy costs, increased transmission sales and timing of short-term incentive payments, partially offset by a one-time bill credit paid to retail customers in 2014 associated with the merger between BHE and NV Energy, increased spending on renewable energy programs and increased rent payments related to the ON Line transmission use agreement.



Investing Activities

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



Financing Activities

Net cash flows for the six-month periods ended June 30, 2014 and 2013 were $(9) million and $(82) million, respectively. The change was primarily due to a decrease in dividends, partially offset by debt tendered in 2014 as a result of the merger between BHE and NV Energy and capital lease payments.



Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of June 30, 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 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. 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 Investor Service or Standard & Poor's, the Company would be subject to limitations under these covenants. 15 --------------------------------------------------------------------------------



Future Uses of Cash

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.



Capital Expenditures

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-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.



Forecasted capital expenditures, 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):

2014 Generation development $ 208 Distribution 112 Transmission system investment 10 Other 53 Total $ 383 Contractual Obligations



As of June 30, 2014, 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.

Regulatory Matters

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, and new regulatory matters occurring in 2014.

The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 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 energy efficiency implementation rate. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate, 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 be effective from July through December 2014 and will reset on January 1, 2015 and remain 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 rate revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rate revenue collected and has recorded a liability of $7 million on the Consolidated Balance Sheets as of June 30, 2014. 16 -------------------------------------------------------------------------------- In May 2014, the Company filed the Emissions Reduction Capacity Replacement Plan in compliance with Senate Bill No. 123 ("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 generation capacity being retired, as required by SB 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. The impacts of the Emissions Reduction Capacity Replacement Plan to the Company's 2014 forecasted capital expenditures are included in the Future Uses of Cash previously discussed. The PUCN has scheduled a hearing on the application beginning in September 2014 and an order is expected in the fourth quarter of 2014. In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requests incremental annual revenue relief in the amount of $38 million or an average price increase of 2%. An order is expected by the end of 2014 and, if approved, the new rates would be effective January 1, 2015. NV Energy has announced plans to join the energy imbalance market ("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 resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In today's environment, utilities in the west outside the California Independent System Operator ("California ISO") rely upon 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 and 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 participation in the EIM that is being established by the California ISO. The filing requests the PUCN to determine that the amended energy supply plan balances the objectives of minimizing the cost of supply and retail price volatility, maximizes the reliability of supply over the remaining term of the plan, optimizes the value of the overall supply portfolio of the Company for the benefit of bundled retail customers and does not contain any features or mechanisms that the PUCN finds would impair the restoration or the creditworthiness of the Company. A hearing on the application was held in July 2014, and an order is expected in August 2014. In April 2014 the California ISO filed the Implementation Agreement entered into by the Company and the California ISO. The Implementation Agreement provides the mechanism by which the Company will compensate the California ISO for its share of the costs to upgrade systems, software licenses and other configuration activities. The Implementation Agreement was approved by the FERC in June 2014.



Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign 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 international 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 forecasted 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. 17 --------------------------------------------------------------------------------



Clean Air Act Regulations

The Clean Air Act is a federal law administered by 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 policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.



Mercury and Air Toxics Standards

The Clean Air Mercury Rule ("CAMR"), issued by the EPA 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, 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. Incremental costs to install and maintain emissions control equipment at the Company's coal-fueled generating facilities and any requirement to shut down what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits were filed against the MATS in the D.C. Circuit. In April 2014, the D.C. Circuit upheld the MATS requirements.



Climate Change

In June 2014, the EPA released proposed regulations to address greenhouse gas 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's proposal, Nevada may utilize 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 is expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The EPA is taking comment on its proposal until October 16, 2014 and is scheduled to issue final rules in June 2015. States are required to submit implementation plans by June 2016, but they may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program. The impacts of the proposal on the Company cannot be determined until the EPA finalizes the proposal and Nevada develops its implementation plan. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of its generating fleet to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs. 18 --------------------------------------------------------------------------------



Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to 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 performance standards for existing electricity generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost 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. In June 2013, the EPA published proposed effluent limitation guidelines and standards for the steam electric power generating sector. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions have changed the effluent discharged from coal- and natural gas-fueled generating facilities. While the EPA expected the final rule to be published in May 2014, the final rule is now scheduled for release by September 30, 2015. It is likely that the new guidelines will impose more stringent limits on wastewater discharges from coal-fueled generating facilities and ash and scrubber ponds. However, until the revised guidelines are finalized, the Company cannot predict the impact on its generating facilities. In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "Waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. As currently proposed, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. The public comment period has been extended on the proposal to October 20, 2014. Until the rule is finalized, the Company cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs, or increased requirements for compensatory mitigation.



Collateral and Contingent Features

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 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, 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, the Company would have been required to post $69 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. 19 --------------------------------------------------------------------------------



New Accounting Pronouncements

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.

Critical Accounting Estimates

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-K for the year ended December 31, 2013. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2013.


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