SIERRA PACIFIC POWER CO - FORM 10-K

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EXCEL - IDEA: XBRL DOCUMENT - SIERRA PACIFIC POWER CO	Financial_Report.xls
EX-31.2 - SPPC EXHIBIT 31.2 - SIERRA PACIFIC POWER CO	sppc123114ex312.htm
EX-32.1 - SPPC EXHIBIT 32.1 - SIERRA PACIFIC POWER CO	sppc123114ex321.htm
EX-31.1 - SPPC EXHIBIT 31.1 - SIERRA PACIFIC POWER CO	sppc123114ex311.htm
EX-12.1 - SPPC EXHIBIT 12.1 - SIERRA PACIFIC POWER CO	sppc123114ex121.htm
EX-23.1 - SPPC EXHIBIT 23.1 - SIERRA PACIFIC POWER CO	sppc123114ex231.htm
EX-32.2 - SPPC EXHIBIT 32.2 - SIERRA PACIFIC POWER CO	sppc123114ex322.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2014

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _____ to _____



Commission File Number	Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization	IRS Employer Identification No.
000-00508	SIERRA PACIFIC POWER COMPANY	88-0044418
	(A Nevada Corporation)
	6100 Neil Road
	Reno, Nevada 89511
	775-834-4011

	Securities registered pursuant to Section 12(b) of the Act: None
	Securities registered pursuant to Section 12(g) of the Act:
	Common Stock, $3.75 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No T

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T

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.

Large accelerated filer o Accelerated filer o Non-accelerated filer T Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No T

All shares of outstanding common stock of Sierra Pacific 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 January 31, 2015, 1,000 shares of common stock, $3.75 par value, were outstanding.

Sierra Pacific Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

TABLE OF CONTENTS



PART I

Item 1.	Business	6
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	20

PART II

Item 5.	Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Selected Financial Data	21
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8.	Financial Statements and Supplementary Data	39
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	65
Item 9A.	Controls and Procedures	65
Item 9B.	Other Information	65

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	66
Item 14.	Principal Accountant Fees and Services	66

PART IV

Item 15.	Exhibits and Financial Statement Schedules	67
Signatures		68

Exhibit Index		69

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 1 through 4, Part II - Items 5 through 7A and Items 9 through 9B, and Part III - Items 10 and 14, the following terms have the definitions indicated.



Sierra Pacific Power Company and Related Entities

Company		Sierra Pacific Power Company and its subsidiaries
BHE		Berkshire Hathaway Energy Company
NV Energy		NV Energy, Inc.
Berkshire Hathaway		Berkshire Hathaway Inc.
Clark Mountain Generating Station		132-megawatt generating facility in Nevada
Nevada Power		Nevada Power Company, an electric utility wholly owned by NV Energy
Ft. Churchill Generating Station		226-megawatt generating facility in Nevada
ON Line		500-kilovolt transmission line connecting the Company and Nevada Power
NV Energize		NV Energy project which includes advanced meter infrastructure, Smart Grid Technology and meter data management
Tracy Generating Station		753-megawatt generating facility in Nevada
Valmy Generating Station		522-megawatt generating facility in Nevada

Certain Industry Terms

AFUDC		Allowance for Funds Used During Construction
California ISO		California Independent System Operator Corporation
Dth		Decatherms
EEIR		Energy Efficiency Implementation Rate
EIM		Energy Imbalance Market
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GHG		Greenhouse Gases
GWh		Gigawatt Hours
IRP		Integrated Resource Plan
kV		Kilovolt
MATS		Mercury and Air Toxics Standards
MW		Megawatts
MWh		Megawatt Hours
NERC		North American Electric Reliability Corporation
PUCN		Public Utilities Commission of Nevada
RPS		Renewable Portfolio Standard
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan

Forward-Looking Statements

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:


•	general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including reliability and safety standards, affecting the Company's operations or related industries;


•	changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;


•	the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner;


•	changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers;


•	performance and availability of the Company's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;


•	a high degree of variance between actual and forecasted load or generation that could impact the Company's hedging strategy and the cost of balancing its generation resources with its retail load obligations;


•	changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;


•	the financial condition and creditworthiness of the Company's significant customers and suppliers;


•	changes in business strategy or development plans;


•	availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for the Company's credit facility;


•	changes in the Company's credit ratings;


•	the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;


•	the impact of inflation on costs and the Company's ability to recover such costs in rates;


•	increases in employee healthcare costs, including the implementation of the Affordable Care Act;


•	the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements related to the Company's participation in NV Energy's benefit plans;


•	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;


•	the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;


•	the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results;


•	the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism and embargoes; and


•	other business or investment considerations that may be disclosed from time to time in the Company's filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in Item 1A and other discussions contained in this Form 10-K. 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.

PART I

Item 1. Business

General

The Company is a United States regulated electric and natural gas utility company serving 0.3 million retail electric customers, including residential, commercial and industrial customers, and 0.2 million retail and transportation natural gas customers in northern Nevada. Generating, transmitting, distributing and selling electricity are the principal business operations of the Company, which is over a service territory covering approximately 41,200 square miles. Additionally, the Company is engaged in distributing, selling and transporting natural gas in an area of about 900 square miles in Reno and Sparks. The Company also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize the economic benefits of electricity generation, retail customer loads and existing wholesale transactions. The Company is subject to comprehensive state and federal regulation. Regulated electric utility operations and regulated natural gas operations are the two segments of the Company. Principal industries served by the Company include gaming, recreation, warehousing, manufacturing and government. In addition to retail sales and natural gas transportation, the Company sells electricity and natural gas to other utilities, municipalities and energy marketing companies on a wholesale basis. The Company is a wholly owned subsidiary of NV Energy, a holding company that also owns Nevada Power and certain other subsidiaries. NV Energy is an indirect wholly owned subsidiary of 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.

On December 19, 2013, the merger contemplated by the Agreement and Plan of Merger dated May 29, 2013 among BHE, Silver Merger Sub, Inc. ("Merger Sub"), BHE's wholly owned subsidiary, and NV Energy, whereby Merger Sub was merged into NV Energy and NV Energy became an indirect wholly owned subsidiary of BHE ("BHE Merger") was completed.

The Company's principal executive offices are located at 6100 Neil Road, Reno, Nevada 89511, and its telephone number is (775) 834-4011. The Company was incorporated in 1912 under the laws of the state of Nevada.

Operations

The Company delivers electricity and natural gas to customers in Nevada. The Company owns or has contracts for coal, natural gas, wind, solar and geothermal resources to provide electricity. This electricity, together with electricity purchased on the wholesale market, is then transmitted via a grid of transmission lines, which are part of the Western Interconnection, the regional grid in the United States. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The electricity is then transformed to lower voltages and delivered to customers through the Company's distribution system.

The Company's primary goal is to provide safe, reliable electricity to its customers at a reasonable cost. In return, the Company expects that all prudently incurred costs to provide such service will be included as allowable costs for ratemaking purposes and that it will be allowed an opportunity to earn a reasonable return on its investments.

The Company's regulated electric and natural gas operations are conducted under numerous nonexclusive franchise agreements, revocable permits and licenses obtained from federal, state and local authorities. The expiration of these franchise agreements range from 2015 through 2032. In addition, the Company operates under certificates of public convenience and necessity as regulated by the PUCN, and as such the Company has an obligation to provide electricity service to those customers within their service territory. In return, the PUCN has established rates on a cost-of-service basis, which are designed to allow the Company an opportunity to recover their costs of providing services and to earn a reasonable return on their investment.

The Company seeks to manage growth in its customer demand through the construction and purchase of cost-effective, environmentally prudent and efficient sources of electricity supply and through energy efficiency programs. The Company and Nevada Power constructed a 500-kV transmission line to connect the two companies. The ON Line transmission line was placed in-service on December 31, 2013. The Company has announced plans to join the EIM in October 2015. The Company and the California ISO will extend the scope of the existing EIM, which 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.

Employees

As of December 31, 2014, the Company had approximately 1,000 employees, of which approximately 600 were covered by a collective bargaining agreement with the International Brotherhood of Electrical Workers.

Regulated Electric Operations

Customers

Electricity sold to retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:



	2014			2013			2012
GWh sold:
Residential	2,268	26	%	2,370	26	%	2,284	26	%
Commercial	2,944	34		2,948	33		2,930	33
Industrial	2,869	33		2,818	31		2,707	30
Other	16	—		16	—		17	—
Total retail	8,097	93		8,152	90		7,938	89
Wholesale	645	7		875	10		1,008	11
Total GWh sold	8,742	100	%	9,027	100	%	8,946	100	%

Average number of retail customers (in thousands):
Residential	285	86	%	281	86	%	279	86	%
Commercial	46	14		46	14		45	14
Total	331	100	%	327	100	%	324	100	%

In addition to the variations in weather from year to year, fluctuations in economic conditions within the service territory and elsewhere can impact customer usage, particularly for gaming, mining and wholesale customers. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.

There are seasonal variations in the Company's electric business that are principally related to the use of electricity for air conditioning and the related effects of weather. Typically, 35-40% of the Company's regulated electric revenue is reported in the months of June, July, August and September.

The annual hourly peak customer demand on the Company's electric system occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 14, 2014, the Company's retail customer usage of electricity caused an hourly peak demand of 1,761 MW on the Company's electric distribution system.

Generating Facilities and Fuel Supply

The Company is required to have resources available to continuously meet its customer needs. The percentage of the Company's energy supplied by energy source varies from year-to-year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. The Company evaluates these factors continuously in order to facilitate economical dispatch of its generating facilities. When factors for one energy source are less favorable, the Company must place more reliance on other energy sources. As long as the Company's purchases are deemed prudent by the PUCN, through its annual prudency review, the Company is permitted to recover the cost of fuel and purchased power. The Company also has the ability to reset quarterly base tariff rates based on the last twelve months fuel costs and purchased power and to reset quarterly deferred energy annual adjustments.

In response to these energy supply challenges, the Company has adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines for procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Company will pursue a process of ongoing regulatory involvement and acknowledgment of the resource portfolio management plans.

The Company has entered into multiple long-term power purchase contracts (three or more years) with suppliers that generate electricity utilizing renewable resources and coal with a total nameplate capacity of 450 MW and contract termination dates ranging from 2016 to 2039. Included in these contracts are 235 MW of nameplate capacity of renewable energy.

The Company manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

The Company has ownership interests in a diverse portfolio of generating facilities. The following table presents certain information regarding the Company's owned generating facilities as of December 31, 2014:



Generating Facility	Location	Energy Source	Installed	Facility Net Capacity (MW)⁽¹⁾	Net Owned Capacity (MW)⁽¹⁾

COAL - Valmy Unit Nos. 1 and 2	Valmy, NV	Coal	1981-1985	522	261

NATURAL GAS:
Tracy⁽²⁾	Sparks, NV	Natural gas/oil	1974-2008	753	753
Ft. Churchill	Yerington, NV	Natural gas/oil	1968-1971	226	226
Clark Mountain	Sparks, NV	Natural gas	1994	132	132
				1,111	1,111

Total available generating capacity				1,633	1,372

(1)

Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource’s nominal rating is the manufacturer’s contractually specified capability under specified conditions. Net Owned Capacity indicates the Company’s ownership of Facility Net Capacity.


(2)	The Company retired two units at Tracy having a combined capacity of 136-megawatts in December 2014.

The following table shows the percentages of the Company's total energy supplied by energy source for the years ended December 31:



	2014		2013		2012

Natural gas	46	%	40	%	44	%
Coal	21		15		11
Total energy generated	67		55		55
Energy purchased - short-term contracts and other	1		4		10
Energy purchased - long-term contracts (renewable)⁽¹⁾	10		10		10
Energy purchased - long-term contracts (non-renewable)	22		31		25
	100	%	100	%	100	%


(1)	All or some of the renewable energy attributes associated with renewable energy purchased may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

Natural Gas

To secure natural gas supplies for the generating facilities the Company either owns or has under long-term contract (tolling arrangements), the Company contracts for firm winter, summer, and annual natural gas supplies with numerous domestic and Canadian suppliers. In 2014, natural gas supply net purchases averaged 127,149 Dth per day, with the winter period contracts averaging 144,786 Dth per day and the summer period contracts averaging 114,703 Dth per day. The Company believes supplies from these sources are presently adequate and available to meet its needs.

The Company contracts for firm natural gas pipeline capacity to transport natural gas from production areas to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems. The Company utilizes natural gas storage leased from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather and other usage factors. The stored natural gas is typically replaced during off-peak months when demand for natural gas is historically lower than during the heating season.

Coal

The Company has a long-term coal contract for the Valmy Generating Station that expires December 31, 2015. Coal shipped under this contract is supplied from Black Butte Coal Company's surface mine in southern Wyoming. As of December 31, 2014, this contract represents 52% of the current forecasted coal requirements of the Valmy Generating Station for 2015. The transportation service contract between the Company and Union Pacific Railroad Company expired December 31, 2014. The Company manages their coal supplies based on anticipated needs and through various arrangements including spot purchases and long- and short‑term contracts. The Company regularly monitors the western coal market for opportunities to enhance its coal supply portfolios.

Transmission and Distribution

The Company's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The Company's transmission system, together with contractual rights on other transmission systems, enables the Company to integrate and access generation resources to meet its customer load requirements. The Company's transmission and distribution systems included approximately 2,100 miles of transmission lines, 17,400 miles of distribution lines and 200 substations as of December 31, 2014.

On December 31, 2013, the Company, along with Nevada Power completed construction and placed in-service ON Line, a 231 mile, 500-kV transmission line connecting the Company's and Nevada Power's service territories. ON Line has enabled the Company and Nevada Power to optimize their generation assets by enhancing their transmission capabilities. ON Line provides the ability to jointly dispatch energy throughout Nevada and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance the Company's and Nevada Power's ability to manage and optimize their generating facilities. ON Line provides between 600 and 800 MW of transfer capability between northern and southern Nevada. ON Line was a joint project between the Company, Nevada Power and Great Basin Transmission, LLC. With the completion of ON Line, the parties completed construction of a 500-kV interconnection between the Robinson Summit substation on the Company's system and the Harry Allen substation on Nevada Power's system. The Company and Nevada Power own a 25% interest in ON Line and have entered into a long-term transmission use agreement with Great Basin Transmission, LLC for its 75% interest in ON Line for a term of 41 years. The Company's and Nevada Power's share of their 25% interest in ON Line and the long-term transmission use agreement is split at 5% and 95%, respectively.

Energy Imbalance Market

The Company has announced plans to join the 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 Western United States outside the EIM footprint 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 expands the real-time component of the California ISO to optimize and balance electricity supply and demand every five minutes across the EIM footprint. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. The EIM is voluntary and available to all balancing authorities in the Western United States. Benefits to customers are expected to increase with renewable resource expansion as more entities join the EIM bringing incremental diversity. 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. In April 2014, the Company filed an application to amend its portfolio optimization procedures contained in the PUCN-approved energy supply plan to include EIM starting October 2015. The amendment reflects the Company's participation in the EIM that is being established by the California ISO.

The filing requested 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. The PUCN issued an order in August 2014 finding that it is in the public interest to grant the application and that NV Energy met the merger stipulation requirement to obtain PUCN approval prior to participating in an EIM. 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.

Future Generation

The Company files IRPs every three years, and as necessary, may file amendments to its IRPs. IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of the Company's customers. Projects approved through the IRP process still remain subject to review by the PUCN. The Company is scheduled to file a triennial IRP before July 1, 2016.

The energy supply function at the Company is responsible for the operation of the Company's owned generation, the procurement of all fuels and purchased power and optimization of resources (e.g., physical and economic dispatch).

There is the potential for continued price volatility in the Company's service territory, particularly during peak periods. Too great a dependence on generation from the wholesale market can lead to power price volatilities depending on available power supply and prevailing natural gas prices. The Company faces load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to the Company. Finally, the Company's own credit situation can have an impact on its ability to enter into transactions.

Within the energy supply planning process, there are three key components covering different time frames:


•	The PUCN-approved long-term IRP which is filed every three years and has a 20-year planning horizon;


•	The PUCN-approved energy supply plan which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate term resource requirements will be met and has a one to three year planning horizon; and


•	Tactical execution activities with a one-month to twelve-month focus.

The energy supply plan operates in conjunction with the PUCN-approved 20-year IRP. It serves as a guide for near-term execution and fulfillment of energy needs. When the energy supply plan calls for executing contracts of longer than three years, PUCN approval is required.

Energy Efficiency Programs

The Company provides a comprehensive set of energy efficiency, demand response and conservation programs to its Nevada electric customers. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, the Company offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. Energy efficiency program costs are recovered through annual rates set by the PUCN, and adjusted based on the Company's annual filing to recover current program costs and any over or under collections from the prior filing, subject to prudence review. During 2014, the Company spent $7 million on energy efficiency programs resulting in an estimated 49,062 MWh of electric energy savings and an estimated 3 MW of electric peak load management.

Regulated Natural Gas Operations

The Company is engaged in the procurement, transportation and distribution of natural gas for customers in its service territory. The Company purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the natural gas from the production areas to the Company's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. The Company sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2014, 14% of the total natural gas delivered through the Company's distribution system was for transportation service.

Customers

The percentages of natural gas sold to retail and wholesale customers by class of customer, total Dth of natural gas sold, total Dth of transportation service and the average number of retail customers for the years ended December 31 were as follows:



	2014		2013		2012

Residential	51	%	49	%	47	%
Commercial⁽¹⁾	25		23		23
Industrial⁽¹⁾	9		8		8
Total retail	85		80		78
Wholesale	15		20		22
	100	%	100	%	100	%

Total Dth of natural gas sold (in thousands)	15,519		19,957		18,058
Total Dth of transportation service (in thousands)	2,275		2,281		2,198
Total average number of retail customers (in thousands)	156		155		153


(1)	Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers that use natural gas principally for heating. Industrial customers are non-residential customers that use natural gas principally for their manufacturing processes.

There are seasonal variations in the Company's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 49-59% of the Company's regulated natural gas revenue is reported in the months of January, February, March and December.

On December 31, 2014, the Company recorded its highest peak-day delivery of 140,813 Dth, which is 22,761 Dth less than the record peak-day delivery of 163,574 Dth set on December 9, 2013. This peak-day delivery consisted of 94% traditional retail sales service and 6% transportation service. The decrease in total Dth of natural gas sold is due to milder weather in 2014.

Fuel Supply and Capacity

The purchase of natural gas for the Company's regulated natural gas operations is done in combination with the purchase of natural gas for the Company's regulated electric operations. In response to energy supply challenges, the Company has adopted an approach to managing the energy supply function that has three primary elements, as discussed earlier under Energy Supply Planning. Similar to the Company's regulated electric operations, as long as the Company's purchases of natural gas are deemed prudent by the PUCN, through its annual prudency review, the Company is permitted to recover the cost of natural gas. The Company also has the ability to reset quarterly base tariff energy rates based on the last twelve months fuel costs and to reset quarterly deferred energy adjustments.

Natural gas property consists principally of natural gas mains and services lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of the Company included 3,200 miles of natural gas mains and service lines as of December 31, 2014.

General Regulation

The Company is subject to comprehensive governmental regulation, which significantly influences its operating environment, prices charged to customers, capital structure, costs and, ultimately, its ability to recover costs. In addition to the following discussion, refer to "Regulatory Matters" in Item 7 of this Form 10-K.

State Regulation

Historically, the PUCN has established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow the utility an opportunity to recover what the PUCN deems to be the utility's reasonable costs of providing services, including a fair opportunity to earn a reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, the utility's cost-of-service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization, and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. The PUCN may, as a result of a statutorily mandated general rate proceeding, adjust rates for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period and (b) the utility's level of investment. The PUCN typically has the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. The utility and such parties may also enter into stipulations regarding changes to rates, though such stipulations are subject to PUCN approval.

The Company's retail electric rates are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Company has established energy cost adjustment mechanisms and other cost recovery mechanisms, which help mitigate its exposure to changes in costs from those assumed in establishing base rates.

The Company generally has an exclusive right to serve retail customers within its service territory, and in turn, has an obligation to provide service to those customers. Certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and retail customers can generate all or a portion of their own energy. In Nevada, state law allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Company, the departure must not burden the Company with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. Currently, there are no material applications pending with the PUCN in the Company's service territory. Also, the Company is evaluating how best to integrate distributed generation resources into its service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.

In addition, by tariff, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.

As of December 31, 2014, there were 17 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 4,800 Dth per day, continue to pay firm and interruptible distribution charges and are responsible for procuring and paying for their own natural gas supply, which reduces Sierra Pacific's purchases, but does not impact net income.

Nevada statutes require the Company to file electric general rate cases at least once every three years with the PUCN. The Company may also file natural gas general rate cases with the PUCN. The Company is also subject to a two-part fuel and purchased power adjustment mechanism. The Company makes quarterly filings to reset Base Tariff Energy Rates ("BTER"), based on the last 12 months fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTER is deferred into a balancing account. During required annual Deferred Energy Accounting Adjustment ("DEAA") proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next subsequent quarterly BTER rate change. Additionally, Nevada regulations allow an electric or natural gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Company received approval from the PUCN and files quarterly adjustments to the DEAA rate to clear amounts deferred into the balancing account. The Company also files annually for the recovery of lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN, as well as, the implementation costs of energy efficiency programs.

Joint Application of the Company and Nevada Power

The Company and Nevada Power became physically interconnected for the first time on January 1, 2014 and are presently joint dispatching generation facilities pursuant to an interim joint dispatch agreement approved by the FERC. In October 2014, the Company and Nevada Power filed a motion for renewal of the interim joint dispatch agreement to extend the agreement through December 2015 and received acceptance from the FERC in November 2014. The Company and Nevada Power are presently seeking PUCN approval of a long-term joint dispatch agreement, which will be filed with the FERC in time to go into effect on January 1, 2016.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Company has implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below.

Wholesale Electricity and Capacity

The FERC regulates the Company's rates charged to wholesale customers for electricity and transmission capacity and related services. Most of the Company's wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility.

The Company's authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. During such reviews, the Company must demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in its market area. The Company's most recent triennial filing was made in July 2013 and approved by the FERC in April 2014. Under the FERC's market-based rules, the Company must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority.

Transmission

The Company's wholesale transmission services are regulated by the FERC under cost-based regulation subject to the Company's open access transmission tariff. These services are offered on a non-discriminatory basis, which means that all potential customers, including the Company, are provided an equal opportunity to access the transmission system. The Company's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct. The Company has made several required compliance filings in accordance with these rules.

FERC Reliability Standards

The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the Western Electricity Coordinating Council ("WECC"), including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC, the NERC and the WECC.

Environmental Laws and Regulations

The Company is subject to federal, state and local laws and regulations regarding air and water quality, RPS, 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 and capital expenditure requirements, 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 and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Item 7 of this Form 10-K for additional information regarding environmental laws and regulations and "Liquidity and Capital Resources" for the Company's forecasted environmental-related capital expenditures.

Item 1A. Risk Factors

We are subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by us, should be made before making an investment decision. Additional risks and uncertainties not presently known or which we currently deem immaterial may also impair our business operations.

We are subject to operating uncertainties and events beyond our control that impact the costs to operate, maintain, repair and replace utility systems, which could adversely affect our consolidated financial results.

The operation of complex utility systems that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of our thermal and other electricity generating facilities and related equipment, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; terrorist activities or military or other actions, including cyberattacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, landslides, wars, terrorism and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. Any of these events or other operational events could significantly reduce or eliminate our revenue or significantly increase our expenses. For example, if we cannot operate our generating facilities at full capacity due to damage caused by a catastrophic event, our revenue could decrease and our expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. The scope, cost and availability of our insurance coverage may change, including the portion that is self-insured. Any reduction of our revenue or increase in our expenses resulting from the risks described above, could adversely affect our consolidated financial results.

We are subject to extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, reliability and other laws and regulations that affect our operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations are continually being proposed and enacted that impose new or revised requirements or standards on our business.

We are required to comply with numerous federal, state and local laws and regulations as described in Item 1 of this Form 10-K that have broad application to our business and limit our ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring or disposing of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transacting with affiliates; and paying dividends or similar distributions. These laws and regulations are followed in developing our safety and compliance programs and procedures and are implemented and enforced by federal, state and local regulatory agencies, such as, among others, the Occupational Safety and Health Administration, the FERC, the EPA, the Nevada Division of Environmental Protection and the PUCN.

Compliance with applicable laws and regulations generally requires us to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs, damages arising out of contaminated properties and refunds, fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, we could be required to shut down some facilities or materially alter their operations. Further, we may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for our operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay us from operating our facilities, developing or favorably locating new facilities or expanding existing facilities. If we fail to comply with any environmental or other regulatory requirements, we may be subject to penalties and fines or other sanctions, including changes to the way our electricity generating facilities are operated that may adversely impact generation. The costs of complying with laws and regulations could adversely affect our consolidated financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require us to increase our purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect our consolidated financial results.

Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition within our service territory; new environmental requirements, including the implementation of RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to our service territory as a result of condemnation or takeover by municipalities or other governmental entities, particularly where we lack the exclusive right to serve our customers; the ability to recover our costs on a timely basis, if at all; or a negative impact on our cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on our business.

Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. We cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions nor can we determine their impact on us at this time; however, any one of these could adversely affect our consolidated financial results through higher capital expenditures and operating costs or restrict or otherwise cause an adverse change in how we operate our business. To the extent that we are not allowed by our regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on our consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on our consolidated financial results.

Recovery of our costs is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect our consolidated financial results.

State Rate Proceedings

Rates are established for our regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases while also requiring us to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.

Retail rates in Nevada are based in part upon the state regulatory commission's determination of total utility costs. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates, and from time-to-time may result in a state regulator requiring refunds to customers. Furthermore, the PUCN generally sets rates based on a test year established in accordance with the PUCN's policies. The test year data adopted may create a lag between the incurrence of a cost and its recovery in rates. The PUCN also decides the allowed levels of expense, investment and capital structure that it deems are just and reasonable in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standards. Additionally, the PUCN establishes the allowed rate of return we will be given an opportunity to earn on our sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the PUCN does not guarantee that we will be able to realize a reasonable rate of return.

FERC Jurisdiction

The FERC authorizes cost-based rates associated with transmission services provided by our transmission facilities. Under the Federal Power Act, we may voluntarily file, or may be obligated to file, for changes, including general rate changes, to our system‑wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which we sell electricity at wholesale and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict our ability to sell electricity at market-based rates, which could adversely affect our consolidated financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.

The NERC has standards in place to ensure the reliability of the electric transmission grid and generation system. We are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.

We are actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and we have significant funding needs related to our planned capital expenditures.

We actively pursue, develop and construct new or expanded facilities. We expect that we will incur substantial annual capital expenditures over the next several years. Such expenditures include and may include in the future, among others, construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems and continued maintenance and upgrades of existing assets.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of our suppliers, customers and contractors. Certain of our construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in‑service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the rates we are able to charge our customers. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect our consolidated financial results.

Furthermore, we depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we are unable to obtain funding from internal and external sources, we may need to postpone or cancel planned capital expenditures.

A significant sustained decrease in demand for electricity or natural gas in the markets served by us would decrease our operating revenue, could impact our planned capital expenditures and could adversely affect our consolidated financial results.


•	a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;


•	an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;


•	efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by us through various conservation, energy efficiency and distributed generation measures and programs;


•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;


•	a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise; and


•	sustained mild weather that reduces heating or cooling needs.

Our operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

In the markets in which we operate, demand for electricity peaks during the summer months when cooling needs are higher. Market prices for electricity also generally peak at that time. In addition, demand for natural gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in our retail natural gas business. Further, extreme weather conditions, such as heat waves, winter storms and floods could cause these seasonal fluctuations to be more pronounced.

As a result, our overall consolidated financial results may fluctuate substantially on a seasonal and quarterly basis. We have historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our consolidated financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase our costs to provide services and could adversely affect our consolidated financial results. The extent of fluctuation in our consolidated financial results may change depending on a number of factors related to our regulatory environment and contractual agreements, including our ability to recover energy costs and terms of our wholesale sale contracts.

We are subject to market risk associated with the wholesale energy markets, which could adversely affect our consolidated financial results.

In general, our primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, we purchase electricity and fuel in the open market as part of our normal operating business. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, we may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when we are a net seller of electricity in the wholesale market, we could earn less revenue. Although we have energy cost adjustment mechanisms under applicable law, the risks associated with changes in market prices may not be fully mitigated.

A downgrade in our credit ratings could negatively affect our access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

Our long-term debt is rated investment grade by various rating agencies. We cannot assure that our long-term debt will continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on our revolving credit agreements and other financing arrangements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.

Most of our large wholesale customers, suppliers and counterparties require us to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings were to decline, especially below investment grade, financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with us. Such amounts may be material and may adversely affect our liquidity and cash flows.

Potential terrorist activities and the impact of military or other actions, including cyberattacks, could adversely affect our consolidated financial results.

The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically, or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject our operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, transmission and other electric utility infrastructure, are potential targets for terrorist attacks, including cyberattacks. Cyberattacks could adversely affect our ability to operate our facilities, information technology and business systems, or compromise confidential customer and employee information. Political, economic, social or financial market instability or damage to or interference with our operating assets or the assets of our customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect us in ways that cannot be predicted at this time. Any of these risks could materially affect our consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism, sustained or significant cyberattacks, or war could also materially adversely affect our ability to raise capital.

We are subject to counterparty credit risk, which could adversely affect our consolidated financial results.

We are subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom we conduct business could impair the ability of these counterparties to meet their payment obligations. We depend on these counterparties to remit payments on a timely basis. We continue to monitor the creditworthiness of our wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if our wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on our liquidity and our consolidated financial results.

We are subject to counterparty performance risk, which could adversely affect our consolidated financial results.

We are subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. We rely on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require us to incur additional expenses to meet customer needs. In addition, when these contracts terminate, we may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

We rely on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require us to find other customers to take the energy at lower prices than the original customers committed to pay. If our wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on our consolidated financial results.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect our consolidated financial results.

Inflation and increases in commodity prices and fuel transportation costs may affect our business by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, we may not be able to pass the costs of inflation on to our customers. If we are unable to manage cost increases or pass them on to our customers, our consolidated financial results could be adversely affected.

Poor performance of plan and fund investments and other factors impacting NV Energy's pension and other postretirement benefit plans in which we participate could unfavorably impact our consolidated financial results.

Costs of providing NV Energy's defined benefit pension and other postretirement benefit plans depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and NV Energy's required or voluntary contributions made to the plans. Certain of NV Energy's pension and other postretirement benefit plans are in underfunded positions. Even if sustained growth in the investments over future periods increases the value of these plans' assets, we will likely be required to make cash contributions to fund these plans in the future. NV Energy's pension and other postretirement benefit plans have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on our liquidity by reducing available cash.

Disruptions in the financial markets could affect our ability to obtain debt financing, draw upon or renew existing credit facilities, and have other adverse effects on us.

Disruptions in the financial markets could affect our ability to obtain debt financing, draw upon or renew existing credit facilities, and have other adverse effects on us. Significant dislocations and liquidity disruptions in the United States and global credit markets, such as those that occurred in 2008 and 2009, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact our ability to access funds on favorable terms or at all. If we are unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of our capital expenditures and our consolidated financial results.

We are involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect our consolidated financial results.

We are, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which we are involved could result in additional material payments substantially in excess of established reserves or in terms that could require that we change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on our consolidated financial results.

The ownership and operation of power generating facilities and transmission lines on federal or Native American lands could result in uncertainty related to continued leaseholds, easements and rights-of-way, which could have a significant impact on our business.

Certain portions of the Company's generating facilities and transmission lines that carry power from these facilities are located on federal or Native American lands pursuant to leases, easements or rights-of-way that are effective for specified periods. The Company is currently unable to predict the outcome of discussions with the federal government, the appropriate Native American tribes, the tribes' governing bodies, or the United States Bureau of Indian Affairs with respect to future arrangements for these leases, easements and rights-of-way, or grants of additional land rights for future Company projects.

BHE could exercise control over us in a manner that would benefit BHE to the detriment of our creditors.

BHE, through its subsidiary, owns all of our common stock and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between BHE and our creditors, BHE could exercise its control in a manner that would benefit BHE to the detriment of our creditors.

Our business operations and financial results could be adversely affected by our inability to realize, or delay in realizing, anticipated benefits or regulatory commitments relating to the BHE Merger.

The BHE Merger may cause an interruption of, or loss of momentum in, the usual activities of our business. The diversion of management's attention, changes in personnel and business methods, and any delays or difficulties encountered in connection with the integration of our operations could adversely affect our business and financial results and could impair our ability to realize the anticipated benefits of the transaction, or to meet regulatory commitments relating to the transaction.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

The Company's properties consist of the physical assets necessary to support its electricity and natural gas business, which include electric generation, transmission and distribution facilities and natural gas distribution facilities. In addition to these physical assets, the Company has rights-of-way and water rights that enable the Company to utilize its facilities. It is the opinion of the Company's management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Substantially all of the Company's property in Nevada is subject to the lien of the Company's General and Refunding Mortgage Indenture filed as an Exhibit to this Form 10‑K. For additional information regarding the Company's properties, refer to Item 1 of this Form 10‑K and Notes 4 and 5 of Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K.

The right to construct and operate the Company's electric transmission and electric and natural gas distribution facilities across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. The Company continues to have the power of eminent domain in Nevada, but it does not have the power of eminent domain with respect to governmental or Native American tribal lands.

With respect to real property, each of the electric transmission and electric and natural gas distribution facilities fall into two basic categories: (1) parcels that are owned in fee, such as certain of the Company's electricity generating facilities and substations; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits, franchises or licenses from landowners or governmental authorities, or from prescription, permitting the use of such land for the construction, operation and maintenance of the electric generation and transmission and electric and natural gas distribution facilities. Subject to litigation or claims disclosed in Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K, the Company believes that it has satisfactory title or interest to all of the real property making up its respective facilities in all material respects.

Item 3. Legal Proceedings

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. Refer to Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding legal proceedings.

Item 4. Mine Safety Disclosures

None.

PART II


Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

All of the Company's common stock is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE.

The Company declared and paid dividends to NV Energy of $105 million in 2014 and $77 million in 2013.

Item 6. Selected Financial Data

The following tables set forth the Company's selected consolidated historical financial data, which should be read in conjunction with the information in Item 7 of this Form 10-K and with the Company's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form 10-K. The selected historical consolidated financial data has been derived from the Company's audited historical Consolidated Financial Statements and notes thereto (in millions).



	Years Ended December 31,
	2014		2013		2012		2011		2010
Consolidated Statement of Operations Data:
Regulated electric operating revenue	$	779	$	747	$	726	$	716	$	837
Regulated natural gas operating revenue	125		106		108		173		191
Operating income	178		140		188		171		181
Net income	87		55		84		60		72

	As of December 31,
	2014		2013		2012		2011		2010
Consolidated Balance Sheet Data:
Total assets	$	3,388	$	3,369	$	3,316	$	3,216	$	3,378
Long-term debt, including current maturities	1,200		1,200		1,179		1,179		1,196
Shareholder's equity	998		1,016		1,039		975		973

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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, natural gas and resources. The Company's electric segment is summer peaking experiencing its highest retail energy sales in response to the demand for air conditioning and its natural gas segment is winter peaking due to sales in response to the demand for heating. 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 Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.

Results of Operations

Net income for the year ended December 31, 2014 was $87 million, an increase of $32 million, or 58% compared to 2013. Net income increased primarily due to regulatory amortizations, $20 million in merger-related expenses in 2013, regulatory disallowances in 2013, lower maintenance costs at the generating stations, favorable other income (expense) related to interest and AFUDC, lower compensation costs, and a one-time bill credit of $5 million to retail customers recorded in 2013 in connection with the BHE Merger. The increase in net income was partially offset by $35 million in lower revenue as a result of reduced customer rates from the 2013 general rate case effective January 1, 2014 and $12 million in impairment charges related to recovery of certain assets not in rates.

Net income for the year ended December 31, 2013 was of $55 million, a decrease of $29 million, or 35% compared to 2012. Net income decreased primarily due to $20 million in merger-related expenses in 2013, regulatory amortizations, $11 million in regulatory disallowances, a one-time bill credit of $5 million to retail customers in 2013 in connection with the BHE Merger and $4 million in impairment charges related to recovery of certain assets not in rates. The decrease in net income was partially offset by an increase in net usage and decreased maintenance costs at the generating stations.

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

Regulated Electric Gross Margin

A comparison of key results related to regulated electric gross margin for the years ended December 31 is as follows:



	2014		2013		Change					2013		2012		Change
Gross margin (in millions):
Operating electric revenue	$	779	$	747	$	32		4	%	$	747	$	726	$	21		3	%
Cost of fuel, energy and capacity	361		292		69			24		292		263		29			11
Gross margin	$	418	$	455	$	(37	)	(8	)	$	455	$	463	$	(8	)	(2	)

GWh sold:
Residential	2,268		2,370		(102		)	(4	)%	2,370		2,284		86			4	%
Commercial	2,944		2,948		(4		)	—		2,948		2,930		18			1
Industrial	2,869		2,818		51			2		2,818		2,707		111			4
Other	16		16		—			—		16		17		(1		)	(6	)
Total retail	8,097		8,152		(55		)	(1	)	8,152		7,938		214			3
Wholesale	645		875		(230		)	(26	)	875		1,008		(133		)	(13	)
Total GWh sold	8,742		9,027		(285		)	(3	)	9,027		8,946		81			1

Average number of retail customers (in thousands):
Residential	285		281		4			1	%	281		279		2			1	%
Commercial	46		46		—			—		46		45		1			2
Total	331		327		4			1		327		324		3			1

Average revenue per MWh:
Retail	$	88.78	$	83.54	$	5.24		6	%	$	83.54	$	83.14	$	0.40		—	%
Wholesale	$	68.34	$	50.99	$	17.35		34	%	$	50.99	$	40.38	$	10.61		26	%

Heating degree days	3,910		5,008		(1,098		)	(22	)%	5,008		4,352		656			15	%
Cooling degree days	1,211		1,177		34			3	%	1,177		1,272		(95		)	(7	)%

Sources of energy (GWh)⁽¹⁾:
Coal	1,870		1,430		440			31	%	1,430		1,025		405			40	%
Natural gas	4,169		3,712		457			12		3,712		3,997		(285		)	(7	)
Total energy generated	6,039		5,142		897			17		5,142		5,022		120			2
Energy purchased	2,943		4,157		(1,214		)	(29	)	4,157		4,055		102			3
Total	8,982		9,299		(317		)	(3	)	9,299		9,077		222			2

Average cost of energy per MWh:
Energy generated⁽²⁾	$	37.38	$	27.81	$	9.57		34	%	$	27.81	$	26.15	$	1.66		6	%
Energy purchased	$	45.95	$	35.83	$	10.12		28	%	$	35.83	$	32.38	$	3.45		11	%

(1) GWh amounts are net of energy used by the related generating facilities.

(2) The average cost per MWh of energy generated includes the cost of fuel and deferrals associated with the generating facilities and does not include

other costs.

Regulated Natural Gas Gross Margin

A comparison of key results related to regulated natural gas gross margin for the years ended December 31 is as follows:



	2014		2013		Change					2013		2012		Change
Gross margin (in millions):
Operating natural gas revenue	$	125	$	106	$	19		18	%	$	106	$	108	$	(2	)	(2	)%
Natural gas purchased for resale	76		56		20			36		56		62		(6		)	(10	)
Gross margin	$	49	$	50	$	(1	)	(2	)	$	50	$	46	$	4		9

Dth sold:
Residential	7,921		9,791		(1,870		)	(19	)%	9,791		8,525		1,266			15	%
Commercial	3,921		4,604		(683		)	(15	)	4,604		4,198		406			10
Industrial	1,416		1,488		(72		)	(5	)	1,488		1,322		166			13
Total retail	13,258		15,883		(2,625		)	(17	)	15,883		14,045		1,838			13

Average number of retail customers (in thousands)	156		155		1			1	%	155		153		2			1	%
Average revenue per retail Dth sold:	$	9.43	$	6.48	$	2.95		46	%	$	6.48	$	6.71	$	(0.23	)	(3	)%
Average cost of natural gas per retail Dth sold	$	5.73	$	4.53	$	1.20		26	%	$	4.53	$	4.41	$	0.12		3	%
Heating degree days	3,910		5,008		(1,098		)	(22	)%	5,008		4,352		656			15	%

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Regulated electric gross margin decreased $37 million, or 8%, for 2014 compared to 2013 primarily due to:


•	$35 million in lower revenue in 2014 as a result of reduced customer rates from the 2013 general rate case effective January 1, 2014;


•	$8 million lower net usage primarily due to a decrease in heating degree days; and


•	$2 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense.

The decrease was partially offset by:


•	$5 million one-time bill credit to retail customers in connection with the BHE Merger in 2013 and


•	$3 million due to customer growth.

Operating and maintenance decreased $39 million, or 20%, for 2014 compared to 2013 primarily due to $11 million in regulatory disallowances in 2013; lower maintenance costs at the generating stations; regulatory amortizations; lower compensation costs; and lower energy efficiency program costs, which are fully recovered in operating revenue. The decrease was partially offset by $12 million in impairment charges related to recovery of certain assets not in rates.

Depreciation and amortization decreased $18 million, or 15%, for 2014 compared to 2013 primarily due to regulatory amortizations.

Property and other taxes increased $1 million, or 4%, for 2014 compared to 2013 primarily due to an increase in property tax assessed values.

The Company incurred costs totaling $20 million in 2013 related to the BHE Merger, consisting of amounts payable under NV Energy's change in control policy of $6 million, accelerated vesting and stock compensation under NV Energy's long-term incentive plan of $7 million, investment banker fees of $6 million and legal and other expenses of $1 million.

Other income (expense) is favorable $8 million, or 15%, for 2014 compared to 2013 primarily due to an increase in interest income on regulatory assets, decreased interest expense as a result of using the proceeds from issuing lower cost debt in August 2013 to repay higher cost debt and an increase in AFUDC from an increase in construction activity.

Income tax expense increased $14 million, or 42%, for 2014 compared to 2013 due to higher income before income tax expense, partially offset by a decrease in the effective tax rate. The effective tax rate was 35% for 2014 and 37% for 2013. The decrease in the effective tax rate is due to certain non-deductible merger related costs in 2013 and other.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Regulated electric gross margin decreased $8 million, or 2%, for 2013 compared to 2012 primarily due to:

•$8 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense;


•	$5 million one-time bill credit to retail customers in connection with the BHE Merger in 2013; and


•	$5 million decrease in energy efficiency implementation revenue.

The decrease in regulated electric gross margin was partially offset by:


•	$7 million increase in net usage;


•	$1 million in higher transmission revenue; and


•	$1 million increase in growth.

Regulated natural gas gross margin increased $4 million, or 9%, for 2013 compared to 2012 primarily due to an increase in customer usage from colder weather.

Operating and maintenance increased $7 million, or 4%, for 2013 compared to 2012 primarily due to $11 million of disallowances related to the Company's general rate case, a disallowance in 2013 of energy efficiency implementation revenue previously recorded in 2012, $4 million of impairment charges related to recovery of certain assets not in rates, higher regulatory expenses and canceled projects. This increase was partially offset by lower energy efficiency program costs, which are fully recovered in operating revenue and lower maintenance costs at the generating stations.

Depreciation and amortization increased $15 million, or 14%, for 2013 compared to 2012 primarily as a result of establishment of regulatory liabilities related to the Company's general rate case of $11 million and higher plant in-service and software amortizations.

Property and other taxes increased $2 million, or 9%, for 2013 compared to 2012 primarily due to an increase in property tax rates.

Interest expense decreased $4 million, or 6%, for 2013 compared to 2012 primarily due to decreased debt amortization expense and financing activities.

Income tax expense decreased $7 million, or 18%, for 2013 compared to 2012 due to lower income before income tax expense and an increase in the effective tax rate. The effective tax rate was 37% for 2013 and 32% for 2012. The increase in the effective tax rate is due to the effects of ratemaking, adjustments due to finalization of the tax audit in 2012 and certain non-deductible merger related costs.

Liquidity and Capital Resources

As of December 31, 2014, the Company's total net liquidity was $272 million as follows (in millions):



Cash and cash equivalents	$	22

Credit facilities⁽¹⁾	250
Less:
Short-term debt	—
Letters of credit and tax exempt bond support	—
Net credit facilities	250

Total net liquidity	$	272

Credit facilities:
Maturity dates	March 2018
Largest single bank commitment as a % of total credit facilities	12.5		%


(1)	Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facility.

Operating Activities

Net cash flows from operating activities for the years ended December 31, 2014 and 2013 were $246 million and $226 million, respectively. The change was primarily due to lower deferred energy refunded to customers, funding of retirement plans in 2013, BHE merger costs and lower compensation payments. These increases were partially offset by lower collections from customers for conservation and renewable programs, lower coal purchases in 2013 and lower collections of energy costs as a result of adjustments to base tariff energy rates.

Net cash flows from operating activities for the years ended December 31, 2013 and 2012 were $226 million and $197 million, respectively. The change was primarily due to higher collections of deferred energy costs, lower spending on renewable energy programs and higher collections of energy efficiency program rate revenue, partially offset by the timing of payments.

Investing Activities

Net cash flows from investing activities for the years ended December 31, 2014 and 2013 were $(186) million and $(139) million, respectively. The change was primarily due to higher capital expenditures for emission control equipment at the Valmy, Ft. Churchill and Tracy Generating Stations.

Net cash flows from investing activities for the years ended December 31, 2013 and 2012 were $(139) million and $(169) million, respectively. The change from 2012 is primarily due to lower capital expenditures for the NV Energize project, partially offset by lower contributions in aid of construction received for the NV Energize project under the American Recovery and Reinvestment Act of 2009.

Financing Activities

Net cash flows from financing activities for the years ended December 31, 2014 and 2013 were $(105) million and $(81) million, respectively. The change was primarily due to higher dividends paid to NV Energy.

Net cash flows from financing activities for the years ended December 31, 2013 and 2012 were $(81) million and $(22) million, respectively. The change was primarily due to higher dividends paid to NV Energy. In August 2013, the Company issued and sold $250 million of its 3.375% Series T General and Refunding Securities, due 2023. In September 2013, the Company paid at maturity the $250 million principal amount of its 5.45% Series Q General and Refunding Securities.

Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2014, the Company has financing authority from the PUCN consisting of the ability to: (1) issue additional long-term debt securities of up to $350 million; (2) refinance up to $348 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of December 31, 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.

Ability to Issue General and Refunding Mortgage Securities

To the extent the Company has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, the Company's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under the Company's indenture. The Company's indenture creates a lien on substantially all of the Company's properties in Nevada. As of December 31, 2014, $1.5 billion of the Company's assets were pledged. The Company had the capacity to issue $900 million of additional general and refunding mortgage securities as of December 31, 2014 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. The Company also has the ability to release property from the lien of the Company's indenture on the basis of net property additions, cash or retired bonds. To the extent the Company releases property from the lien of the Company's indenture, it will reduce the amount of securities issuable under the indenture.

Future Uses of Cash

Capital Expenditures

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 acquisition of existing assets.

Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):



	Historical						Forecasted
	2012		2013		2014		2015		2016		2017

Generation development	$	21	$	48	$	51	$	71	$	24	$	18
Distribution	64		63		89		113		116		91
Transmission system investment	11		7		19		9		36		13
Other	73		21		27		27		15		14
Total	$	169	$	139	$	186	$	220	$	191	$	136

The Company estimates that it will spend approximately $547 million on capital projects over the next three years, excluding non-cash equity AFUDC and other non-cash items.

Contractual Obligations

The Company has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes the Company's material contractual cash obligations as of December 31, 2014 (in millions):



	Payments Due by Periods
			2016-		2018-		2020 and
	2015		2017		2019		After		Total

Long-term debt	$	—	$	450	$	—	$	716	$	1,166
Interest payments on long-term debt⁽¹⁾	53		66		53		355		527
Capital leases, including interest⁽²⁾	1		1		1		1		4
ON Line financial lease, including interest⁽²⁾	2		5		5		45		57
Fuel and capacity contract commitments⁽¹⁾	253		287		192		534		1,266
Operating leases and easements⁽¹⁾	5		7		6		45		63
Asset retirement obligations	3		1		—		10		14
Maintenance, service and other contracts⁽¹⁾	7		15		15		71		108
Total contractual cash obligations	$	324	$	832	$	272	$	1,777	$	3,205


(1)	Not reflected on the Consolidated Balance Sheets.


(2)	Interest is not reflected on the Consolidated Balance Sheets.

The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7 and Note 7) and uncertain tax positions (Note 11), which have not been included in the above table because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Regulatory Matters

The Company is subject to comprehensive regulation. In addition to the discussion contained herein regarding regulatory matters, refer to Item 1 of this Form 10-K for further discussion regarding the Company's general regulatory framework.

State Regulatory Matters

In June 2013, the Company filed its statutorily required triennial general rate case for its Nevada electric operations and updated the filing in August 2013. The filing, as updated, requested a return on equity of 10.40% and a decrease in general rates of $5 million. The PUCN issued its order in December 2013 granting a return on equity of 9.80% and a $37 million general rate decrease, which was effective January 1, 2014. As a result of the final order the Company recorded $2 million of operating and maintenance on the Consolidated Statements of Operations related to general study costs originally deferred.

In June 2013, the Company filed a general rate case for its natural gas operations and updated the filing in August 2013. The filing, as updated, requested a return on equity of 10.35% and an increase in general rates of $6 million. The PUCN issued its order in December 2013 granting a return on equity of 9.7% and a $4 million increase to general rates which was effective January 1, 2014.

In March 2013, the Company filed applications with the PUCN for the twelve-month period ended December 31, 2012 to reset EEIR elements. In September 2013, the PUCN issued an order indicating that EEIR revenue should not contribute to the Company earning more than its authorized rate of return. As the Company earned in excess of its authorized rate of return in 2012, the PUCN disallowed approximately $5 million in EEIR revenue (including carrying charges) and the Company recorded a charge to operating and maintenance on the Consolidated Statements of Operations for the year ended December 31, 2013.

The PUCN's final order approving the BHE Merger 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 EEIR and energy efficiency program rates. In June 2014, the PUCN accepted a stipulation to adjust the 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 EEIR was 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 EEIR revenue collected. As a result, the Company has deferred recognition of EEIR collected and has recorded a liability of $2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2014.

General Rate Case

In connection with Nevada Power's general rate case filing in May 2014, as required by the PUCN, the Company made a "companion filing" for the purpose of documenting the costs and benefits of the Company's investment in the advanced service delivery program. In October 2014, the PUCN issued an order in the companion filing issued with the general rate case order that, among other things, provided for the implementation of new rates effective January 1, 2015 to begin recovery of costs associated with advance service delivery. The recovery of advanced service delivery costs will increase annual revenue approximately $10 million. As a result of the PUCN order in the companion filing issued with the Nevada Power general rate case order, the Company recorded $7 million in asset impairments related to property, plant and equipment and $1 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.

Advanced Metering Infrastructure

In October 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 the requested information with the PUCN. Management cannot assess or predict the outcome of these inquires at this time.

Federal Regulatory Matters

2013 FERC Transmission Rate Case

In May 2013, the Company, along with Nevada Power, 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. In August 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.

In September 2014, the Company, along with Nevada Power, 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 interim rate relief was issued, which authorizes the Company to institute the interim rates effective September 1, 2014, and begin billing transmission customers under the settlement rates for service provided on and after that date. In January 2015, the FERC approved the settlement and refunds will be processed in 2015. As of December 31, 2014, the Company accrued $2 million for amounts subject to rate refund, which is included in other current liabilities on the Consolidated Balance Sheets.

Environmental Laws and Regulations

The Company is subject to federal, state and local laws and regulations regarding air and water quality, RPS, 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 and local 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.

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 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. The major Clean Air Act programs most directly affecting the Company's operations are described below.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants, consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present.

In November 2014, the EPA released a new proposal to strengthen the national ambient air quality standard for ground level ozone from the current level of 75 parts per billion to a level between 65 and 70 parts per billion. Review or revision is required to be complete by October 2015. Until the standards' review or revision is complete the EPA is proceeding with implementation of the 2008 ozone standards.

In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide national ambient air quality standard.

In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013. Although the EPA's July 2013 designations did not impact the Company's generating facilities, the EPA's assessment of sulfur dioxide area designations will continue with the deployment of additional sulfur dioxide monitoring networks across the country.

In December 2012, the EPA finalized more stringent fine particulate matter national ambient air quality standards, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the Company operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the Company does not anticipate that any impacts of the revised standard will be significant.

As new, more stringent national ambient air quality standards are adopted, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could also become more difficult in nonattainment areas. Until new requirements are promulgated and additional monitoring and modeling is conducted, the impacts on the Company cannot be determined.

Mercury and Air Toxics Standards

In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final rule, 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 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 is proceeding with additional actions to reduce mercury emissions through the installation of controls and use of sorbent injection at certain of its coal-fueled generating facilities to otherwise comply with the final rule's standards.

Incremental costs to install and maintain emissions control equipment at the Company's coal-fueled generating facilities and any resulting shut down of what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. Numerous lawsuits have been filed in the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. The outcome of the United States Supreme Court's decision is uncertain and until the court renders its decision or otherwise implements a stay of the MATS requirements, the Company is proceeding to fulfill its legal obligations to comply with the MATS.

Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Certain of the Company's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

Environmental groups have challenged both of the EPA's final determinations with respect to Nevada's regional haze SIP. In May 2012, WildEarth Guardians petitioned the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") to review the EPA's March 2012 approval of Nevada's SIP for all affected units and emissions except nitrogen oxides controls at the Reid Gardner Generating Station. Both the Company and Nevada Power intervened in the lawsuit and briefing was completed in February 2013.The matter was heard before the Ninth Circuit in May 2014. On July 17, 2014, the Ninth Circuit issued its decision, dismissing the petition in part because WildEarth Guardians did not have standing to challenge a portion of the SIP, and denying the petition in part based on its conclusion that the EPA's approval of the Nevada SIP was appropriate.

New Source Review

Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (a) beginning construction of a new major stationary source of a regulated pollutant or (b) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations require pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the most effective emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by the EPA, states, environmental groups and others, potentially subject a company to material fines and other sanctions and remedies, including installation of enhanced pollution controls and funding of supplemental environmental projects.

Numerous changes have been proposed to the NSR rules and regulations over a period of years. In addition to the proposed changes, differing interpretations by the EPA and the courts create risk and uncertainty for entities when seeking permits for new projects and installing emissions controls at existing facilities under NSR requirements. The Company monitors these changes and interpretations to ensure permitting activities are conducted in accordance with the applicable requirements.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information and supporting documentation from numerous utilities regarding their capital projects for various coal-fueled generating facilities. A NSR enforcement case against an unrelated utility has been decided by the United States Supreme Court, holding that an increase in the annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting.

In June 2009, the Company received a request from the EPA Region 9 pursuant to Section 114 of the Clean Air Act for information regarding current and historic operations and capital project information for the Company's Valmy Generating Station. The Company operates and owns 50% of the Valmy coal-fueled generating facility. The Company submitted its response to the EPA in December 2009. The Company cannot predict the outcome of this matter at this time.

Climate Change

While significant measures to regulate GHG emissions at the federal level were considered by the United States Congress in 2010, comprehensive climate change legislation has not been adopted. In June 2013, President Obama issued a Climate Action Plan, which, among other things, required the EPA to address GHG emissions from new, modified and existing fossil-fueled generating facilities under the Clean Air Act. Regulation of GHG emissions has proceeded under various provisions of the Clean Air Act since the EPA's December 2009 findings that GHG emissions threaten public health and welfare.

GHG Tailoring Rule

In May 2010, the EPA finalized the GHG "Tailoring Rule" requiring new or modified sources of GHG emissions with increases

of 75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginning in January 2011. New or existing major sources are also subject to Title V operating permit requirements for GHG. Beginning July 1, 2011 through June 30, 2013, new construction projects that emit GHG emissions of at least 100,000 tons per year and modifications of existing facilities that increase GHG emissions by at least 75,000 tons per year became subject to permitting requirements. While the final rule also required facilities that were previously not subject to Title V permitting requirements to obtain Title V permits if they emit at least 100,000 tons per year of carbon dioxide equivalents, litigation over the Tailoring Rule resulted in a decision by the United States Supreme Court in June 2014 that the EPA could not utilize the Tailoring Rule to impose GHG permitting requirements on sources not otherwise subject to Clean Air Act permitting provisions. That decision did not impact the Company’s sources that are already subject to Clean Air Act permitting. To date, permitting authorities implementing the GHG Tailoring Rule have included efficiency improvements to demonstrate compliance with best available control technology for GHG, as well as requiring emissions limits for GHGs in permits, which have not had a material impact on the Company's consolidated financial results.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. The EPA entered into a settlement agreement with a number of parties, including certain state governments and environmental groups, in December 2010 to promulgate emissions standards covering GHG. In April 2012, the EPA proposed new source performance standards for new fossil-fueled generating facilities that would limit emissions of carbon dioxide to 1,000 pounds per MWh. As part of his Climate Action Plan, President Obama announced a national climate change strategy and issued a presidential memorandum requiring the EPA to issue a re-proposed GHG new source performance standard for fossil-fueled generating facilities by September 2013. The September 2013 GHG new source performance standards released by the EPA set different standards for coal-fueled and natural gas-fueled generating facilities. The proposed standard for natural gas-fueled generating facilities considers the size of the unit and the electricity sent to the grid from the unit, establishing a standard of 1,000 to 1,100 pounds of carbon dioxide per MWh. The standard proposed for coal-fueled generating facilities is 1,100 pounds of carbon dioxide per MWh on an annual basis or 1,000 to 1,050 pounds of carbon dioxide per MWh averaged over a seven-year period, both of which would require partial carbon capture and sequestration. The proposed standards were published in the Federal Register January 8, 2014, and the public comment period closed in May 2014. Any new fossil-fueled generating facilities constructed by the Company will be required to meet the GHG new source performance standards, which are expected to be finalized in the summer of 2015.

In June 2014, the EPA released proposed regulations to address GHG 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, states 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 public comment period closed December 1, 2014 and the final guidelines are scheduled to be issued in the summer of 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 the states develop their implementation plans. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

In November 2014, President Obama announced the United States and China had reached a climate change agreement under which the United States intends to achieve an economy-wide target of reducing its emissions by 26% to 28% below 2005 levels in 2025 and China would peak its GHG emissions around 2030 and increase the share of non-fossil fuels in primary energy consumption to 20% by 2030.

While the discussion continues at the federal and international level over the direction of climate change policy, several states have continued to implement state-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governmental, non-governmental and environmental organizations have become more active in pursuing climate change related litigation under existing laws.

New federal, regional state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Company, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Company include:


•	Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;


•	Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;


•	Additional costs may be incurred to purchase and deploy new generating technologies;


•	Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;


•	Operating costs may be higher and generating unit outputs may be lower;


•	Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and


•	The Company's electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.

The impact of events or conditions caused by climate change, whether from natural processes or human activities, could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Company's existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.

GHG Litigation

The Company closely monitors ongoing environmental litigation. Numerous lawsuits have been unsuccessfully pursued against the industry that attempt to link GHG emissions to public or private harm. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. These cases have typically been appealed to federal appellate courts and, in certain circumstances, to the United States Supreme Court. An adverse ruling in similar cases would likely result in increased regulation and costs for GHG emitters, including the Company's generating facilities.

Renewable Portfolio Standards

Since 1997, the Company has been required to comply with a RPS. Current law requires the Company to meet 18% of its energy requirements with renewable resources for 2014, 20% for 2015 through 2019, 22% for 2020 and 2024, and 25% for 2025 and thereafter. The RPS also requires 5% of the portfolio requirement come from solar resources through 2015 and increasing to 6% in 2016. Nevada law also permits energy efficiency measures to be used to satisfy a portion of the RPS through 2025, subject to certain limitations. The Company is in compliance with these requirements.

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. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014, and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). The Company does not utilize once-through cooling water intake or discharge structures at any of its generating facilities. All of the Company's generating stations are designed to have either minimal or zero discharge; therefore, they are not expected to be impacted by the §316(b) final rule.

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 associated 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 closed November 14, 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.

Coal Combustion Byproduct Disposal

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 ("RCRA"). The public comment period closed in November 2010. The final rule was released by the EPA on December 19, 2014 and will be effective 180 days after it is published in the Federal Register. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the 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 does not operate evaporative surface impoundments that are likely to fall within the definition of the final rule and operates one landfill that contains coal combustion byproducts. The Company is assessing the requirements of the final rule to determine the costs of compliance.

Other

Other laws, regulations and agencies to which the Company is subject include, but are not limited to:


•	The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs.

The Company expects to be allowed to recover the prudently incurred costs to comply with the environmental laws and regulations discussed above. The Company's planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Company at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Company has established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.

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 bilateral rights to demand cash or other security if credit exposures on a net 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 December 31, 2014, 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 December 31, 2014, the Company would have been required to post $13 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.

In July 2010, the President signed into law the Dodd-Frank Reform Act. The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating markets and firms not previously regulated, and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act are and have been subject to extensive rulemaking proceedings being conducted both jointly and independently by multiple regulatory agencies, many of which have been completed and others that have not yet been finalized.

The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of position limits, mandatory clearing, exchange trading, capital, margin, reporting, recordkeeping and business conduct requirements. Many of these requirements are primarily for "swap dealers" and "major swap participants," but many of these also impose some requirements on almost all market participants, including the Company. The Dodd-Frank Reform Act provides certain exemptions from many of these requirements for commercial end-users when using derivatives to hedge or mitigate commercial risk of their businesses. The Company qualifies or believes it will qualify for many of these exemptions. The Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging or mitigating commercial risk and has determined that it is not a swap dealer or major swap participant. The outcome of pending and remaining Dodd-Frank Reform Act rulemaking proceedings cannot be predicted but requirements resulting from these proceedings could directly impact the Company or could have impacts to energy and other markets in general that could have an impact on the Company's consolidated financial results.

Inflation

Historically, overall inflation and changing prices in the economies where the Company operates has not had a significant impact on the Company's consolidated financial results. The Company operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, the Company is allowed to include prudent costs in its rates, including the impact of inflation after the Company experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. The Company attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

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 8 of this Form 10-K.

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. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

The Company prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Company defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Company's ability to recover its costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss). Total regulatory assets were $476 million and total regulatory liabilities were $301 million as of December 31, 2014. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's regulatory assets and liabilities.

Impairment of Long-Lived Assets

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2014, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.

Income Taxes

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state and local income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 11 of Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K for additional information regarding the Company's income taxes.

Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company is required to pass on to its customers are charged or credited directly to a regulatory asset or liability. As of December 31, 2014 and 2013, these amounts were recognized as regulatory assets of $94 million and $96 million, respectively, and regulatory liabilities of $8 million and $9 million, respectively, and will be included in regulated rates when the temporary differences reverse.

Revenue Recognition - Unbilled Revenue

Revenue is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $57 million as of December 31, 2014. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. The Company has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's contracts accounted for as derivatives.

Commodity Price Risk

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 market 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, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. 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 is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. The Company does not engage in a material amount of proprietary trading activities. 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 does not hedge its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include the costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

Interest Rate Risk

The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short- and long-term debt.

As of December 31, 2014 and 2013, the Company had short- and long-term variable-rate obligations totaling $215 million and $214 million, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2014 and 2013.

Credit Risk

The Company is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Company's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, the Company analyzes the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Company enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Company exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2014, the Company's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.

Item 8. Financial Statements and Supplementary Data



Report of Independent Registered Public Accounting Firm			40

Consolidated Balance Sheets			41

Consolidated Statements of Operations			42

Consolidated Statements of Changes in Shareholder's Equity			43

Consolidated Statements of Cash Flows			44

Notes to Consolidated Financial Statements			45

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.


/s/	Deloitte & Touche LLP

Las Vegas, Nevada

February 27, 2015

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions, except share data)



	As of December 31,
	2014			2013
ASSETS

Current assets:
Cash and cash equivalents	$	22		$	67
Accounts receivable, net	127			156
Inventories	40			43
Regulatory assets	32			15
Deferred income taxes	42			48
Other current assets	20			23
Total current assets	283			352

Property, plant and equipment, net	2,640			2,552
Regulatory assets	444			427
Other assets	21			38

Total assets	$	3,388		$	3,369

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	127		$	151
Accrued interest	15			15
Accrued property, income and other taxes	12			12
Regulatory liabilities	39			37
Current portion of long-term debt	1			1
Customer deposits	16			14
Other current liabilities	14			9
Total current liabilities	224			239

Long-term debt	1,199			1,199
Regulatory liabilities	262			243
Deferred income taxes	566			525
Other long-term liabilities	139			147
Total liabilities	2,390			2,353

Commitments and contingencies (Note 15)

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—			—
Other paid-in capital	1,111			1,111
Accumulated deficit	(111		)	(93		)
Accumulated other comprehensive loss, net	(2		)	(2		)
Total shareholder's equity	998			1,016

Total liabilities and shareholder's equity	$	3,388		$	3,369

The accompanying notes are an integral part of the consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)



	Years Ended December 31,
	2014			2013			2012

Operating revenue:
Regulated electric	$	779		$	747		$	726
Regulated natural gas	125			106			108
Total operating revenue	904			853			834

Operating costs and expenses:
Cost of fuel, energy and capacity	361			292			263
Natural gas purchased for resale	76			56			62
Operating and maintenance	158			197			190
Depreciation and amortization	105			123			108
Property and other taxes	26			25			23
Merger-related	—			20			—
Total operating costs and expenses	726			713			646

Operating income	178			140			188

Other income (expense):
Interest expense	(61		)	(61		)	(65		)
Allowance for borrowed funds	2			1			2
Allowance for equity funds	3			2			3
Other, net	12			6			(4		)
Total other income (expense)	(44		)	(52		)	(64		)

Income before income tax expense	134			88			124
Income tax expense	47			33			40
Net income	$	87		$	55		$	84

The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Amounts in millions, except shares)



									Accumulated
				Other					Other			Total
	Common Stock			Paid-in		Accumulated			Comprehensive			Shareholder's
	Shares	Amount		Capital		Deficit			Loss, Net			Equity
Balance, December 31, 2011	1,000	$	—	$	1,111	$	(135	)	$	(1	)	$	975
Net income	—	—		—		84			—			84
Dividends declared	—	—		—		(20		)	—			(20		)
Balance, December 31, 2012	1,000	—		1,111		(71		)	(1		)	1,039
Net income	—	—		—		55			—			55
Dividends declared	—	—		—		(77		)	—			(77		)
Other	—	—		—		—			(1		)	(1		)
Balance, December 31, 2013	1,000	—		1,111		(93		)	(2		)	1,016
Net income	—	—		—		87			—			87
Dividends declared	—	—		—		(105		)	—			(105		)
Balance, December 31, 2014	1,000	$	—	$	1,111	$	(111	)	$	(2	)	$	998

The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)



	Years Ended December 31,
	2014			2013			2012

Cash flows from operating activities:
Net income	$	87		$	55		$	84
Adjustments to reconcile net income to net cash from operating activities:
Loss on nonrecurring items	14			—			—
Depreciation and amortization	105			123			108
Deferred income taxes and amortization of investment tax credits	47			36			48
Allowance for equity funds	(3		)	(2		)	(3		)
Amortization of deferred energy	19			(43		)	(108		)
Deferred energy	(30		)	(24		)	73
Amortization of other regulatory assets	34			77			75
Other, net	(22		)	20			(2		)
Changes in other assets and liabilities:
Accounts receivable and other assets	14			(17		)	(43		)
Inventories	3			17			(4		)
Accounts payable and other liabilities	(22		)	(16		)	(31		)
Net cash flows from operating activities	246			226			197

Cash flows from investing activities:
Capital expenditures	(196		)	(157		)	(211		)
Contributions in aid of construction and customer advances	10			18			42
Net cash flows from investing activities	(186		)	(139		)	(169		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt, net of costs	—			247			(2		)
Repayments of long-term debt	1			(251		)	—
Dividends paid	(105		)	(77		)	(20		)
Other, net	(1		)	—			—
Net cash flows from financing activities	(105		)	(81		)	(22		)

Net change in cash and cash equivalents	(45		)	6			6
Cash and cash equivalents at beginning of period	67			61			55
Cash and cash equivalents at end of period	$	22		$	67		$	61

The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Operations

Sierra Pacific 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 Nevada Power Company ("Nevada Power") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. 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 transaction was approved by the board of directors of both NV Energy and BHE and the shareholders of NV Energy and received various regulatory approvals, including the Public Utilities Commission of Nevada ("PUCN"), subject to certain stipulations. The stipulations included, among others:


•	A one-time bill credit to retail customers of the Company of $5 million credited to retail customers over one billing cycle beginning within 30 days of the close of the BHE Merger.


•	BHE and NV Energy agreed to not seek recovery of the acquisition premium, transaction and transition costs associated with the BHE Merger from customers.

•

The Company will not seek to collect lost revenues as described in section 704.9524 of the Nevada Administrative Code for calendar year 2013 in 2014 rates, and will not seek collection of lost revenues in excess of 50% of what the Company could otherwise request for calendar year 2014 in 2015 rates. NV Energy also agreed to work cooperatively with PUCN staff and the Nevada Bureau of Consumer Protection ("BCP") to develop a legislative or administrative alternative to the current mechanism that would retain the objective of encouraging investment in energy efficiency and that is acceptable to NV Energy, PUCN staff and the BCP. NV Energy and the BCP also agree to work in good faith to have a legislative or administrative alternative adopted.

•

Normal rate case rules and procedures apply to costs and revenues, and any under or over earnings will accrue to the Company until the next rate case filing after 2014, subject to specified adjustments for intercompany charges from BHE and its other subsidiaries as described in the PUCN Joint Application. The commitment does not preclude parties from proposing any other adjustments to test year or certification period results.

(2) Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of the Company and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.

The impacts of acquisition accounting from the BHE Merger were not reflected on the Consolidated Financial Statements of the Company.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other assets on the Consolidated Balance Sheets.

Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectibility of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The Company also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. The change in the balance of the allowance for doubtful accounts, which is included in accounts receivable, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):



	2014			2013			2012
Beginning balance	$	1		$	1		$	1
Charged to operating costs and expenses, net	2			2			1
Write-offs, net	(1		)	(2		)	(1		)
Ending balance	$	2		$	1		$	1

Derivatives

The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. 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. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.

For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.

For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.

Inventories

Inventories consist mainly of materials and supplies totaling $32 million and $30 million as of December 31, 2014 and 2013, respectively, and fuel, which includes coal stocks, stored natural gas and fuel oil, totaling $8 million and $13 million as of December 31, 2014 and 2013, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the PUCN.

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Company to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. The Company's AFUDC rate used during both 2014 and 2013 was 7.58% and 7.86% for electric, 4.96% and 5.15% for natural gas and 7.28% and 7.59% for common facilities, respectively.

Asset Retirement Obligations

The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.

Management's methodology to assess its legal obligation includes an inventory of assets by the Company's system and components and a review of rights-of-way and easements, regulatory orders, leases and federal, state and local environmental laws. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl have met the requirements for an ARO.

Impairment

Income Taxes

Berkshire Hathaway commenced including the Company in its United States federal income tax return on December 20, 2013 in connection with the BHE Merger. Prior to December 20, 2013, the Company filed a consolidated United States federal income tax return with NV Energy. Consistent with established regulatory practice, the Company's provision for income taxes has been computed on a separate return basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company is required to pass on to its customers are charged or credited directly to a regulatory asset or liability. As of December 31, 2014 and 2013, these amounts were recognized as regulatory assets of $94 million and $96 million, respectively, and regulatory liabilities of $8 million and $9 million, respectively, and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.

Revenue Recognition

Revenue is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2014 and 2013, unbilled revenue was $57 million and $65 million, respectively, and is included in accounts receivable, net on the Consolidated Balance Sheets. Rates are established by regulators or contractual arrangements. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

The Company primarily buys energy and natural gas to satisfy its customer load requirements. Due to changes in retail customer load requirements, the Company may not take physical delivery of the energy or natural gas. The Company may sell the excess energy or natural gas to the wholesale market. In such instances, it is the Company's policy to record such sales net in cost of fuel, energy and capacity.

Unamortized Debt Premiums, Discounts and Financing Costs

Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, which creates FASB Accounting Standards Codification ("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 is effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. 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.

In February 2013, the FASB issued ASU No. 2013-04, which amends FASB ASC Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as well as other information about those obligations. The Company adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

(3) Merger-Related Activities

On December 17, 2013, the PUCN approved the Joint Application related to the BHE Merger filed by BHE and NV Energy, subject to certain stipulations. The stipulations included, among others, a one-time bill credit to retail customers of the Company of $5 million credited to retail customers over one billing cycle beginning within 30 days of the close of the BHE Merger. The bill credit was included as a reduction to operating revenue on the Consolidated Statements of Operations for the year ended December 31, 2013.

The Company incurred costs totaling $20 million related to the BHE Merger, consisting of: (i) $6 million for amounts payable under NV Energy's change in control policy; (ii) $7 million for accelerated vesting and stock compensation under NV Energy's long-term incentive plan; (iii) $6 million for investment banker fees paid by NV Energy and (iv) $1 million for legal and other expenses. The costs were included in merger-related expenses on the Consolidated Statements of Operations for the year ended December 31, 2013.

(4) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):



	Depreciable Life	2014			2013
Utility plant in-service:
Electric generation	40 - 125 years	$	1,036		$	1,070
Electric distribution	20 - 70 years	1,321			1,289
Electric transmission	50 - 70 years	719			685
Electric intangible plant	5 - 65 years	123			138
Natural gas distribution	40 - 70 years	366			357
Natural gas intangible plant	8 - 10 years	13			13
Common general	5 - 65 years	234			212
Utility plant in-service		3,812			3,764
Accumulated depreciation and amortization		(1,300		)	(1,301		)
Utility plant in-service, net		2,512			2,463
Construction work-in-progress		128			89
Property, plant and equipment, net		$	2,640		$	2,552

All of the Company's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. The Company's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2014, 2013 and 2012 were 3.0%, 3.0% and 2.9%, respectively. The Company is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate case filings.

Construction work-in-progress is related to the construction of regulated assets.

Impairment of Regulated Assets Not In Rates

The Company recorded an impairment charge of $12 million and $4 million in operating and maintenance on the Consolidated Statements of Operations for the years ended December 31, 2014 and 2013, respectively, related to the recovery of certain assets not currently in rates. Included in the 2014 impairment is $8 million related to the settlement of the "companion filing" in the 2014 Nevada Power general rate case.

(5) Jointly Owned Utility Facilities

Under joint facility ownership agreements, the Company, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities. The amounts shown in the table below represent the Company's share in each jointly owned facility as of December 31, 2014 (dollars in millions):



						Construction
	Company	Facility In		Accumulated		Work-in-
	Share	Service		Depreciation		Progress

Valmy Generating Station	50%	$	343	$	213	$	27
ON Line Transmission Line⁽¹⁾	1	7		—		1
Valmy Transmission	50	4		2		—
Total		$	354	$	215	$	28


(1)	ON Line, a 500-kilovolt transmission line connecting the Company and Nevada Power, was placed in-service December 2013. The Company and Nevada Power entered into a long-term transmission use agreement, in which the Company and Nevada Power have 25% interest and Great Basin Transmission South, LLC has 75% interest. Refer to Note 8 for additional information.

(6) Regulatory Matters

Regulatory assets represent costs that are expected to be recovered in future rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):



	Weighted
	Average
	Remaining Life	2014		2013

Employee benefit plans⁽²⁾	10 years	$	115	$	90
Deferred income taxes⁽¹⁾	29 years	94		96
Merger costs from 1999 merger	32 years	87		90
Abandoned projects	9 years	51		59
Deferred excess energy costs	1 year	32		17
Loss on reacquired debt	17 years	24		27
Legacy meters	6 years	21		24
Asset retirement obligations	15 years	12		10
Unrealized loss on regulated derivative contracts	2 years	1		13
Other	Various	39		16
Total regulatory assets		$	476	$	442

Reflected as:
Current assets		$	32	$	15
Other assets		444		427
Total regulatory assets		$	476	$	442


(1)	Amounts represent income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.


(2)	Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

The Company had regulatory assets not earning a return on investment of $269 million as of December 31, 2014 that primarily related to deferred income taxes, merger costs from 1999 merger, loss on reacquired debt, legacy meters and asset retirement obligations. As of December 31, 2013, the Company had regulatory assets not earning a return on investment of $232 million, that primarily related to deferred income taxes, merger costs from 1999 merger, a portion of deferred excess energy costs and unrealized loss on regulated derivative contracts.

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):



	Weighted
	Average
	Remaining Life	2014		2013

Cost of removal⁽¹⁾	41 years	$	233	$	219
Renewable energy program	1 year	32		24
Energy efficiency program	1 year	7		12
Deferred income taxes	11 years	8		9
Other	Various	21		16
Total regulatory liabilities		$	301	$	280

Reflected as:
Current liabilities		$	39	$	37
Other long-term liabilities		262		243
Total regulatory liabilities		$	301	$	280


(1)	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN.

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and is included in the table above as deferred excess energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy over collected. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Energy Efficiency Implementation Rates and Energy Efficiency Program Rates

In July 2010, regulations were adopted by the PUCN that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN through energy efficiency implementation rates ("EEIR"). As a result, the Company files annually in March to adjust energy efficiency program rates and EEIR for over- or under-collected balances, which are effective in October of the same year.

The PUCN's final order approving the BHE Merger stipulated that the Company will not seek recovery of any lost revenue for calendar year 2013 and, for the calendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. As a result, for the year ended December 31, 2013, the Company has not recorded revenue for EEIR and has recorded a regulatory liability to refund to customers amounts collected in 2013 of $5 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2013. In February 2014, the Company filed an application with the PUCN to reset the EEIR and energy efficiency program rates. In June 2014, the PUCN accepted a stipulation to adjust the 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 EEIR was 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 EEIR revenue collected. As a result, the Company has deferred recognition of EEIR collected and has recorded a liability of $2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2014.

General Rate Case

2013 FERC Transmission Rate Case

(7) Credit Facility

The Company has a $250 million secured credit facility expiring in March 2018. The credit facility, which is for general corporate purposes for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") or a base rate, at the Company's option, plus a spread that varies based on the Company's credit ratings for its senior secured long‑term debt securities. As of December 31, 2014 and 2013, the Company had no borrowings outstanding under the credit facility. Amounts due under the Company's credit facility are collateralized by the Company's general and refunding mortgage bonds. The credit facility requires the Company's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.68 to 1.0 as of the last day of each quarter.

(8) Long-Term Debt

The Company's long-term debt consists of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):



	Par Value		2014		2013
General and Refunding Mortgage Securities:
6.000% Series M, due 2016	$	450	$	452	$	453
3.375% Series T, due 2023	250		250		250
6.750% Series P, due 2037	252		258		259
Variable-rate series (2014-0.464% to 0.466%, 2013-0.459% to 0.463%):
Pollution Control Revenue Bonds Series 2006A, due 2031	58		58		58
Pollution Control Revenue Bonds Series 2006B, due 2036	75		75		75
Pollution Control Revenue Bonds Series 2006C, due 2036	81		81		81
Capital and financial lease obligations - 2.700% to 8.814%, due through 2054	26		26		24
Total long-term debt	$	1,192	$	1,200	$	1,200

Reflected as:
Current portion of long-term debt			$	1	$	1
Long-term debt			1,199		1,199
Total long-term debt			$	1,200	$	1,200

The consummation of the BHE Merger also triggered mandatory redemption requirements under financing agreements of the Company. As a result, the Company offered to purchase $702 million of debt at 101% of par. The tender offer expired in January 2014 with no amounts tendered.

In August 2013, the Company issued and sold $250 million of its 3.375% Series T General and Refunding Securities, due 2023. The $248 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% Series Q General and Refunding Securities, which matured in September 2013.

Annual Payment on Long-Term Debt

The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 2015 and thereafter, excluding unamortized premiums and discounts, are as follows (in millions):



	Long-term		Capital and Financial
	Debt		Lease Obligations			Total

2015	$	—	$	3		$	3
2016	450		3			453
2017	—		3			3
2018	—		3			3
2019	—		3			3
Thereafter	716		46			762
Total	1,166		61			1,227
Unamortized premium	8		—			8
Amounts representing interest	—		(35		)	(35		)
Total	$	1,174	$	26		$	1,200

Utility plant of $1.5 billion is subject to the liens of the Company's indentures under which its respective General and Refunding Mortgage Securities are issued.

Capital and Financial Lease Obligations


•	The Company has master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. Lease terms average seven years under the master lease agreement. Capital assets of $3 million and $2 million were included in property, plant and equipment, net as of December 31, 2014 and 2013, respectively.

•

ON Line was placed in-service on December 31, 2013. The Company and Nevada Power entered into a long-term transmission use agreement, in which the Company and Nevada Power have 25% interest and Great Basin Transmission South, LLC has 75% interest. Refer to Note 5 for additional information. The Company's and Nevada Power's share of the long-term transmission use agreement and ownership interest is split at 5% and 95%, respectively. The term is for 41 years with the agreement ending December 31, 2054. Payments began on January 31, 2014. ON Line assets of $22 million was included in property, plant and equipment, net as of December 31, 2014 and 2013.


(9)	Fair Value Measurements

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, principally related to derivative contracts, that are measured at fair value on the Consolidated Balance Sheets 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:


•	Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

•

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).


•	Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The Company's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present 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-term debt as of December 31 (in millions):



	2014				2013
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,174	$	1,301	$	1,176	$	1,270

(10) Other, Net

Other, net as shown on the Consolidated Statements of Operations for the years ended December 31 consists of the following (in millions):



	2014		2013			2012

Interest and dividend income	$	1	$	1		$	1
Donations	—		—			(1		)
Interest expense on regulatory items	8		(1		)	(1		)
Other	3		6			(3		)
Total other, net	$	12	$	6		$	(4	)


(11)	Income Taxes

Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):



	2014			2013			2012

Current – Federal	$	—		$	(2	)	$	(7	)
Deferred:
Federal	48			38			48
State	—			(2		)	—
Total deferred	48			36			48

Investment tax credits	(1		)	(1		)	(1		)
Total income tax expense	$	47		$	33		$	40

A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:



	2014		2013		2012

Federal statutory income tax rate	35	%	35	%	35	%
Non-deductible BHE Merger related expenses	—		1		(1	)
Effects of ratemaking	1		1		—
Other	(1	)	—		(2	)
Effective income tax rate	35	%	37	%	32	%

The net deferred income tax liability consists of the following as of December 31 (in millions):



	2014			2013
Deferred income tax assets:
Net operating loss and credit carryforwards	$	56		$	61
Employee benefit plans	22			12
Regulatory liabilities	21			9
Capital and financial lease liabilities	9			8
Customer Advances	7			—
Other	15			40
Total deferred income tax assets	$	130		$	130

Deferred income tax liabilities:
Property related items	$	(478	)	$	(441	)
Regulatory assets	(147		)	(148		)
Capital and financial leases	(9		)	(8		)
Other	(20		)	(10		)
Total deferred income tax liabilities	$	(654	)	$	(607	)
Net deferred income tax liability	$	(524	)	$	(477	)

Reflected as:
Deferred income taxes - current	$	42		$	48
Deferred income taxes - long-term	(566		)	(525		)
Net deferred income tax liability	$	(524	)	$	(477	)

The following table provides the Company's federal net operating loss and tax credit carryforwards and expiration dates as of December 31, 2014 (in millions):



Net operating loss carryforwards	$	146
Deferred income taxes on federal net operating loss carryforwards	$	51
Expiration dates	2030-2034

Other tax credits	$	5
Expiration dates	2015-2034

The United States federal jurisdiction is the only significant income tax jurisdiction for NV Energy. In July 2012, the United States Internal Revenue Service and the Joint Committee on Taxation concluded their examination of NV Energy with respect to its United States federal income tax returns for December 31, 2005 through December 31, 2008.

A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):



	2014		2013

Beginning balance	$	3	$	3
Additions for tax positions of prior years	—		—
Reductions for tax positions of prior years	—		—
Ending balance	$	3	$	3

As of December 31, 2014 and 2013, the Company had unrecognized tax benefits totaling $1 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.

(12) Related Party Transactions

The Company provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $- million, $- million and $3 million for the years ended December 31, 2014, 2013 and 2012, respectively. There were no receivables or payables associated with these services as of December 31, 2014 and 2013.

The Company provided electricity to Nevada Power of $8 million, $1 million and $1 million for the years ended December 31, 2014, 2013 and 2012, respectively. Receivables associated with these transactions were $4 million and $- million as of December 31, 2014 and 2013. The Company purchased electricity from Nevada Power of $33 million, $36 million and $20 million for the years ended December 31, 2014, 2013 and 2012, respectively. Payables associated with these transactions were $7 million and $3 million as of December 31, 2014 and 2013, respectively.

The Company incurs intercompany administrative and shared facility costs between NV Energy and Nevada Power. These transactions are governed by an intercompany service agreement and are priced at cost. NV Energy provided services to the Company of $9 million, $19 million and $12 million for the years ending December 31, 2014, 2013 and 2012, respectively. The Company provided services to Nevada Power of $16 million, $- million and $- million for the years ended December 31, 2014, 2013 and 2012, respectively. Nevada Power provided services to the Company of $20 million, $- million and $- million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, the Company's Consolidated Balance Sheets included amounts due to NV Energy of $20 million and $28 million, respectively. As of December 31, 2014 and 2013, the Company's Consolidated Balance Sheets included receivables due to Nevada Power of $5 million and $6 million, respectively.

Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of the Company and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.

(13) Retirement Plan and Postretirement Benefits

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 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. The Company contributed $20 million and $15 million to the Qualified Pension Plan for the years ended December 31, 2013 and 2012, respectively, and did not make a contribution in 2014. For the Other Postretirement Plans, the Company contributed $- million, $5 million and $7 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company did not make any contributions to the Non-Qualified Pension Plans for the years ended December 31, 2014, 2013 and 2012. 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).

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31(in millions):



	2014			2013
Qualified Pension Plan:
Other assets	$	—		$	18
Other long-term liabilities	(13		)	—

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)
Other long-term liabilities	(10		)	(11		)

Other Postretirement Plans -
Other long-term liabilities	(33		)	(38		)

(14) Asset Retirement Obligations

The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $233 million and $219 million as of December 31, 2014 and 2013, respectively.

The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):



	2014		2013

Evaporative ponds and dry ash landfills	$	2	$	7
Asbestos	5		6
Other	4		3
Total asset retirement obligations	$	11	$	16

The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):



	2014			2013

Beginning balance	$	16		$	15
Change in estimated costs	(6		)	—
Accretion	1			1
Ending balance	$	11		$	16

Reflected as:
Other current liabilities	$	3		$	—
Other long-term liabilities	8			16
	$	11		$	16

Certain of the Company's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, the Company is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.

In December 2014, the EPA released its final rule regulating the management and disposal of coal combustion byproducts resulting from the operation of coal-fueled generating facilities, including requirements for the operation and closure of surface impoundment and ash landfill facilities. The final rule will be effective 180 days after it is published in the Federal Register. 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. The Company is currently evaluating the requirements and costs of the new rule and cannot determine the impact on its ARO liabilities at this time.


(15)	Commitments and Contingencies

Environmental Laws and Regulations

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.

Valmy Generation Station

In June 2009, 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 Valmy Generating Station located in Valmy, Nevada. The Company co-owns and operates this coal-fueled generating facility. Idaho Power Company owns the remaining 50%. 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 in December 2009 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.

Legal Matters

Newmont Nevada Energy Investment - TS Power Plant

Newmont Nevada Energy Investment, LLC ("Newmont") owns a 203 megawatt coal-fueled power plant facility located in Eureka County, Nevada (the "TS Power Plant") that is interconnected to the Company's transmission system. As a result of system modifications required for a 500-kV transmission line connecting the Company and Nevada Power ("ON Line"), Newmont needed to install certain protection equipment at its TS Power Plant. Newmont brought suit against the Company in the Second Judicial District of Nevada seeking declaratory relief and to enjoin the operation at full capacity of certain equipment to be installed by the Company for the ON Line project, until such time as Newmont completes the design, fabrication and installation of protection equipment at its power plant to protect its generator from potential adverse effects caused by the operation of the Company's equipment at full capacity. In addition, Newmont's complaint asserted a claim under the parties' interconnection agreement seeking to recover the cost of making the necessary modifications to the TS Power Plant.

A hearing on Newmont's motion for a preliminary injunction was held during the week of August 12, 2013, after which the trial court concluded that it would enter an order enjoining the Company from operating its equipment at full capacity from January 1, 2014 until approximately April 8, 2014, and from approximately June 1, 2014 to June 30, 2014 (or the time Newmont has completed the installation of its protection equipment), so as to allow installation and testing of protection equipment at the TS Power Plant. The district court issued the order in December 2013. Newmont posted the required $1 million bond and subsequently filed a complaint with the FERC to address the issue of who will pay for the protection equipment and its installation at the TS Power Plant. In April 2014, the FERC issued an order directing the Company to pay the costs of studies relating to subsynchronous resonance conducted by Newmont and the installation of the protection equipment at the TS Power Plant. The costs are a component of the ON Line construction costs and are shared between the Company and Nevada Power at 5% and 95%, respectively. The protection equipment has been installed at the TS Power Plant and the Company's facilities are now operating at full capacity. Accordingly, the $1 million bond posted by Newmont has been released. Newmont is also seeking recovery of legal fees associated with litigating this matter. The parties have finalized a settlement in this matter and final documents dismissing the claims have been filed with the court, in November 2014. The terms of the settlement did not have a material impact on the Company.

Caughlin Fire

On November 18, 2011, a fire was reported in the hills near Reno, Nevada (the "Caughlin Fire"). In January 2012, the Reno Fire Department issued a report in which they opined that "this fire was most likely the result of an electrical event in the area," and that "something such as a tree branch hitting the power-line" was a likely cause of the fire. The Company is continuing its investigation in the matter.

Subrogation lawsuits and individual claimant lawsuits have been filed against the Company in relation to the Caughlin Fire. The subrogation lawsuits have been brought by various insurance companies, and involve similar causes of action (negligence, inverse condemnation, trespass, nuisance, subrogation and strict liability). The individual lawsuits mostly alleged similar causes of action as outlined in the subrogation claims. The Company reached settlement of all of the subrogation lawsuits in July 2014, which did not have a material impact to the Company.

In February 2015, all but one of the remaining individual plaintiffs entered into a proposed settlement agreement. This proposed settlement agreement will not have a material impact on the Company. The Company plans to vigorously defend the remaining lawsuit. The Company cannot assess or predict the outcome of the remaining lawsuit or if any other litigation may be brought on this matter.

Touch America Holdings

In January 2015, Brent Williams as Trustee of Touch America Holdings ("Touch America") filed a complaint in the United States Bankruptcy Court for the District of Delaware against the Company alleging Touch America owns certain underground communications conduit located at various places in the western United States that the Company also claims to own. The conduit at issue is believed to be located between Reno, Nevada and Spanish Fork, Utah as part of a larger duct bank system. The Company is preparing a response to the complaint which will be filed in March 2015 pursuant to applicable deadlines. The Company plans to vigorously defend the matter. The Company cannot assess or predict the outcome of the case at this time.

Commitments

The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2014 are as follows (in millions):



											2020 and
	2015		2016		2017		2018		2019		Thereafter		Total
Contract type:
Fuel and capacity contract commitments	$	253	$	173	$	114	$	102	$	90	$	534	$	1,266
Operating leases and easements	5		4		3		3		3		45		63
Maintenance, service and other contracts	7		7		8		7		8		71		108
Total commitments	$	265	$	184	$	125	$	112	$	101	$	650	$	1,437

Fuel and Capacity Contract Commitments

Purchased Power

The Company has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2015 to 2037. Purchased power includes contracts which meet the definition of a lease. The Company's rent expense for purchase power contracts which met the lease criteria for 2014, 2013 and 2012 were $68 million, $63 million and $60 million, respectively, and are recorded as cost of fuel, energy and capacity on the Consolidated Statements of Operations.

Coal and Natural Gas

The Company has several long-term contracts for the purchase and transport of coal and natural gas. The expiration of the purchase contracts range from 2015 to 2016 and the expiration of the transportation contracts range from 2016 to 2030.

Operating Leases

The Company has non-cancelable operating leases primarily for office equipment, office space, certain operating facilities, vehicles and land. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company also has non-cancelable easements for land. Rent expense on non-cancelable operating leases totaled $6 million, $5 million and $6 million for the year-ended December 31, 2014, 2013 and 2012, respectively.

Maintenance, Service and Other Contracts

The Company has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2023 to 2039.

(16) Supplemental Cash Flow Disclosures

The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):



	2014		2013		2012

Supplemental disclosure of cash flow information -
Interest paid, net of amounts capitalized	$	54	$	59	$	60

Supplemental disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions	$	31	$	37	$	27
Capital and financial lease obligations incurred	$	1	$	22	$	—

(17) Segment Information

The Company has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

The Company believes presenting gross margin allows the reader to assess the impact of the Company's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale.

The following tables provide information on a reportable segment basis for the years ended December 31 (in millions):



	Years Ended December 31,
	2014		2013		2012
Operating revenue:
Regulated electric	$	779	$	747	$	726
Regulated gas	125		106		108
Total operating revenue	$	904	$	853	$	834

Cost of sales:
Regulated electric	$	361	$	292	$	263
Regulated gas	76		56		62
Total cost of sales	$	437	$	348	$	325

Gross margin:
Regulated electric	$	418	$	455	$	463
Regulated gas	49		50		46
Total gross margin	$	467	$	505	$	509

Operating and maintenance:
Regulated electric	$	140	$	176	$	169
Regulated gas	18		21		21
Total operating and maintenance	$	158	$	197	$	190

Depreciation and amortization:
Regulated electric	$	90	$	106	$	95
Regulated gas	15		17		13
Total depreciation and amortization	$	105	$	123	$	108

Operating income:
Regulated electric	$	165	$	134	$	179
Regulated gas	13		6		9
Total operating income	$	178	$	140	$	188

Interest expense, net of allowance for borrowed funds:
Regulated electric	$	55	$	55	$	57
Regulated gas	4		5		6
Total interest expense, net of allowance for borrowed funds	$	59	$	60	$	63

Income tax (benefit) expenses:
Regulated electric	$	43	$	32	$	40
Regulated gas	4		1		—
Total income tax (benefit) expense	$	47	$	33	$	40



	Years Ended December 31,
	2014		2013		2012
Capital expenditures:
Regulated electric	$	177	$	141	$	191
Regulated gas	19		16		20
Total capital expenditures	$	196	$	157	$	211

	As of December 31,
Total assets:	2014		2013		2012
Regulated electric	$	3,031	$	2,957	$	2,919
Regulated gas	327		335		319
Regulated common assets⁽¹⁾	30		77		78
Total assets	$	3,388	$	3,369	$	3,316


(1)	Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.

(18) Unaudited Quarterly Operating Results (in millions)



	Three-Month Periods Ended
	March 31,		June 30,		September 30,		December 31,
	2014		2014		2014		2014
Regulated electric operating revenue	$	177	$	179	$	233	$	190
Regulated natural gas operating revenue	44		21		18		42
Operating income	46		31		60		41
Net income	22		14		31		20


	Three-Month Periods Ended
	March 31,		June 30,		September 30,		December 31,
	2013		2013		2013		2013
Regulated electric operating revenue	$	172	$	175	$	213	$	187
Regulated natural gas operating revenue	40		20		14		32
Operating income	49		30		58		3
Net income	22		11		29		(7		)

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

At the end of the period covered by this Annual Report on Form 10-K, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the President and Chief Executive Officer (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 and Chief Executive Officer (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 SEC's rules and forms, and is accumulated and communicated to management, including the Company's President and Chief Executive Officer (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 December 31, 2014 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including the President and Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), the Company's management conducted an evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2014 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, the Company's management used the criteria set forth in the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in "Internal Control - Integrated Framework (2013)", the Company's management concluded that the Company's internal control over financial reporting was effective as of December 31, 2014.

Sierra Pacific Power Company

February 27, 2015

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) for Form 10-K.

Item 11. Executive Compensation

Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) for Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) for Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) for Form 10-K.

Item 14. Principal Accountant Fees and Services

The following table shows the Company's fees paid or accrued for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu Limited, and their respective affiliates (collectively, the "Deloitte Entities") for each of the last two years (in millions):



	2014		2013

Audit fees⁽¹⁾	$	0.9	$	1.1
Audit-related fees⁽²⁾	—		—
Tax fees⁽³⁾	—		—
Total	$	0.9	$	1.1


(1)	Audit fees include fees for the audit of the Company's consolidated financial statements and interim reviews of the Company's quarterly financial statements, audit services provided in connection with required statutory audits, comfort letters, consents and other services related to SEC matters.


(2)	Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of employee benefit plans and consultations on various accounting and reporting matters.


(3)	Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal and state tax compliance, tax return preparation and tax audits.

The audit committee of BHE has considered whether the non-audit services provided to the Company by the Deloitte Entities impaired the independence of the Deloitte Entities and concluded that they did not. All of the services performed by the Deloitte Entities were pre-approved in a manner consistent with the pre-approval policy adopted by the audit committee of BHE. The policy provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the Deloitte Entities to the Company. The policy (a) identifies the guiding principles that must be considered by the audit committee of BHE in approving services to ensure that the Deloitte Entities' independence is not impaired; (b) describes the audit, audit-related and tax services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, requests to provide services that require specific approval by the audit committee of BHE will be submitted to the audit committee of BHE by both the Company's independent auditor and BHE's Chief Financial Officer. All requests for services to be provided by the independent auditor that do not require specific approval by the audit committee of BHE will be submitted to BHE's Chief Financial Officer and must include a detailed description of the services to be rendered. BHE's Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the audit committee of BHE. The audit committee of BHE will be informed on a timely basis of any such services rendered by the independent auditor.

PART IV

Item 15. Exhibits and Financial Statement Schedules



(a)		Financial Statements and Schedule

	(i)	Financial Statements:

		Consolidated Financial Statements are included in Item 8	39

	(ii)	Financial Statement Schedules:
		All schedules have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.

(b)		Exhibits

		The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report.	69

(c)		Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b).

		Not applicable.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 on this 27th day of February, 2015.



	SIERRA PACIFIC POWER COMPANY

	/s/ Paul J. Caudill
	Paul J. Caudill
	President and Chief Executive Officer
	(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:



Signature	Title	Date

/s/ Paul J. Caudill	President and Chief Executive Officer	February 27, 2015
Paul J. Caudill	(principal executive officer)

/s/ E. Kevin Bethel	Senior Vice President, Chief Financial	February 27, 2015
E. Kevin Bethel	Officer and Director
	(principal financial and accounting officer)

/s/ Douglas A. Cannon	Senior Vice President, Corporate Secretary,	February 27, 2015
Douglas A. Cannon	General Counsel and Director

/s/ Patrick S. Egan	Senior Vice President, Customer Services	February 27, 2015
Patrick S. Egan	and Director

/s/ Kevin C. Geraghty	Director	February 27, 2015
Kevin C. Geraghty

/s/ Francis P. Gonzales	Director	February 27, 2015
Francis P. Gonzales

/s/ John C. Owens	Director	February 27, 2015
John C. Owens

/s/ Tony F. Sanchez, III	Senior Vice President, Government and	February 27, 2015
Tony F. Sanchez, III	Community Strategy and Director

EXHIBIT INDEX

Exhibits Filed Herewith



Exhibit No.	Description

12.1	Computation of Ratios of Earnings to Fixed Charges.

23.1	Consent of Deloitte & Touche LLP.

31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	The following financial information from Sierra Pacific Power Company's Annual Report on Form 10-K for the year ended December 31, 2014 is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholder's Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.

Exhibits Incorporated by Reference



Exhibit No.	Description

3.1	Restated Articles of Incorporation of Sierra Pacific Power Company, dated October 25, 2006 (filed as Exhibit 3.1 to Form 10-Q for quarter ended September 30, 2006).

3.2	By-Laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).

4.1	General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001).

4.2	Second Supplemental Indenture, dated as of October 30, 2006, to subject additional properties of Sierra Pacific Power Company located in the State of California to the lien of the General and Refunding Mortgage Indenture and to correct defects in the original Indenture (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2006).

4.3	Agreement of Resignation, Appointment and Acceptance dated November 6, 2009 by and among Sierra Pacific Power Company d/b/a NV Energy, The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.3 to Form 10-K for the year ended December 31, 2009).

4.4	Officer's Certificate establishing the terms of Sierra Pacific Power Company's 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006).

4.5	Form of First Supplemental Officer's Certificate establishing the terms of Sierra Pacific Power Company's 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.2 to Form 8-K dated August 18, 2009).

4.6	Form of Sierra Pacific Power Company's 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated August 18, 2009).

4.7	Officer's Certificate establishing the terms of Sierra Pacific Power Company's 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Exhibit 4.2 to Form 8-K dated June 27, 2007).

4.8	Form of Sierra Pacific Power Company's 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated June 27, 2007).

4.9	Officer's Certificate establishing the terms of Sierra Pacific Power Company's 3.375% General and Refunding Mortgage Notes, Series T, due 2023 (filed as Exhibit 4.1 to Form 8-K dated August 12, 2013).



Exhibit No.	Description
4.10	Form of Sierra Pacific Power Company's 3.375% General and Refunding Mortgage Notes, Series T, due 2023 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated August 12, 2013).

10.1	Transmission Use and Capacity Exchange Agreement between Nevada Power Company, Sierra Pacific Power Company and Great Basin Transmission, LLC dated August 20, 2010 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2010).

10.2	Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007A) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2007).

10.3	Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007B) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2007).

10.4	Financing Agreement dated November 1, 2006 between Humboldt County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Humboldt County, Nevada $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006) (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2006).

10.5	Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $58,750,000 Gas Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A) (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 2006).

10.6	Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $75,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B) (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 2006).

10.7	Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $84,800,000 Gas and Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C) (filed as Exhibit 10(E) to Form 10-K for the year ended December 31, 2006).

10.8	Credit Agreement dated March 23, 2012 between Sierra Pacific Power Company d/b/a NV Energy and Wells Fargo Bank, N.A., as administrative agent for the lenders (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 30, 2012).

10.9	$250,000,000 Amended and Restated Credit Agreement, dated as of June 27, 2014, among Sierra Pacific Power Company, as borrower, the Initial Lenders, Wells Fargo Bank, National Association, as administrative agent and swingline lender and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated June 27, 2014).

14.1	Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers.

SIERRA PACIFIC POWER CO - FORM 10-K - February 27, 2015

Attached files

SIERRA PACIFIC POWER CO Reports