10-K 1 d464015d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

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, 2012

OR

 

[    ]

  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 1-6541

LOEWS CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware             13-2646102
(State or other jurisdiction of             (I.R.S. Employer  
incorporation or organization)             Identification No.)

667 Madison Avenue, New York, N.Y. 10065-8087

(Address of principal executive offices) (Zip Code)

(212) 521-2000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

  Title of each class  

                

    Name of each exchange on which registered    

Loews Common Stock, par value $0.01 per share         New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

    Yes             X                  No                            

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                              No           X            

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           X                 No                         

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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           X                 No                         

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 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. [ X ].

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. (Check one):

Large accelerated filer      X     Accelerated filer               Non-accelerated filer               Smaller reporting company              

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

    Yes                              No           X            

The aggregate market value of voting and non-voting common equity held by non-affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $12,707,000,000.

As of February 15, 2013, there were 391,885,833 shares of Loews common stock outstanding.

Documents Incorporated by Reference:

Portions of the Registrant’s definitive proxy statement intended to be filed by Registrant with the Commission prior to April 30, 2013 are incorporated by reference into Part III of this Report.

 

 

 


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LOEWS CORPORATION

INDEX TO ANNUAL REPORT ON

FORM 10-K FILED WITH THE

SECURITIES AND EXCHANGE COMMISSION

For the Year Ended December 31, 2012

 

Item    Page  
 No.     PART I      No.   

   1

  

Business

  
  

CNA Financial Corporation

       
  

Diamond Offshore Drilling, Inc.

       
  

Boardwalk Pipeline Partners, LP

     12    
  

HighMount Exploration & Production LLC

     15    
  

Loews Hotels Holding Corporation

     20    
  

Executive Officers of the Registrant

     21    
  

Available Information

     22    

   1A

  

Risk Factors

     22    

   1B

  

Unresolved Staff Comments

     43    

   2

  

Properties

     43    

   3

  

Legal Proceedings

     43    

   4

  

Mine Safety Disclosures

     43    
   PART II   

   5

  

Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     44    

   6

  

Selected Financial Data

     46    

   7

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     47    

   7A

  

Quantitative and Qualitative Disclosures about Market Risk

     94    

   8

  

Financial Statements and Supplementary Data

     98    

   9

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     177    

   9A

  

Controls and Procedures

     177    

   9B

  

Other Information

     177    
   PART III   
  

Certain information called for by Part III (Items 10, 11, 12, 13 and 14) has been omitted as Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the close of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.

  
   PART IV   

15    

  

Exhibits and Financial Statement Schedules

     178    

 

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PART I

Unless the context otherwise requires, references in this Report to “Loews Corporation,” “we,” “our,” “us” or like terms refer to the business of Loews Corporation excluding its subsidiaries.

Item 1. Business.

We are a holding company. Our subsidiaries are engaged in the following lines of business:

 

   

commercial property and casualty insurance (CNA Financial Corporation, a 90% owned subsidiary);

 

   

operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc., a 50.4% owned subsidiary);

 

   

transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas (Boardwalk Pipeline Partners, LP, a 55% owned subsidiary);

 

   

exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC, a wholly owned subsidiary); and

 

   

operation of hotels (Loews Hotels Holding Corporation, a wholly owned subsidiary).

Please read information relating to our major business segments from which we derive revenue and income contained in Note 20 of the Notes to Consolidated Financial Statements, included under Item 8.

CNA FINANCIAL CORPORATION

CNA Financial Corporation (together with its subsidiaries, “CNA”) was incorporated in 1967 and is an insurance holding company. CNA’s property and casualty and remaining life & group insurance operations are primarily conducted by Continental Casualty Company (“CCC”), incorporated in 1897, and The Continental Insurance Company (“CIC”), organized in 1853, and certain other affiliates. CIC became a subsidiary of CNA in 1995 as a result of the acquisition of The Continental Corporation (“Continental”). CNA accounted for 65.6%, 63.4% and 63.0% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

CNA’s insurance products primarily include commercial property and casualty coverages, including surety. CNA’s services include risk management, information services, warranty and claims administration. CNA’s products and services are primarily marketed through independent agents, brokers and managing general underwriters to a wide variety of customers, including small, medium and large businesses, insurance companies, associations, professionals and other groups.

CNA’s property and casualty field structure consists of 49 underwriting locations across the United States. In addition, there are five centralized processing operations which handle policy processing, billing and collection activities, and also act as call centers to optimize service. The claims structure consists of two regional claim centers designed to efficiently handle the high volume of low severity claims including property damage, liability, and workers’ compensation medical only claims, and 16 principal claim offices handling the more complex claims. In addition, CNA has underwriting and claim capabilities in Canada and Europe.

CNA Specialty

CNA Specialty includes the following business groups:

Professional & Management Liability: Professional & Management Liability provides management and professional liability insurance and risk management services and other specialized property and casualty coverages in the United States. This group provides professional liability coverages to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. Professional & Management Liability also provides directors and officers (“D&O”), employment practices, fiduciary and fidelity coverages. Specific areas of focus include small and mid-size firms as well as privately held firms and not-for-profit

 

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organizations, where tailored products for this client segment are offered. Products within Professional & Management Liability are distributed through brokers, independent agents and managing general underwriters. Professional & Management Liability, through CNA HealthPro, also offers insurance products to serve the health care industry. Products include professional liability and associated standard property and casualty coverages, and are distributed on a national basis through brokers, independent agents and managing general underwriters. Key customer segments include long term care facilities, allied health care providers, life sciences, dental professionals and mid-size and large health care facilities.

International:  International provides similar management and professional liability insurance and other specialized property and casualty coverages, through similar distribution channels, in Canada and Europe.

Surety:  Surety offers small, medium and large contract and commercial surety bonds. CNA Surety provides surety and fidelity bonds in all 50 states through a network of independent agencies. On June 10, 2011, CNA completed the acquisition of the noncontrolling interest of CNA Surety.

Warranty and Alternative Risks:  Warranty and Alternative Risks provides extended service contracts and related products that provide protection from the financial burden associated with mechanical breakdown and other related losses, primarily for vehicles and portable electronic communication devices.

CNA Commercial

CNA Commercial’s property products include standard and excess property coverages, as well as marine coverage, and boiler and machinery. Casualty products include standard casualty insurance products such as workers’ compensation, general and product liability, commercial auto and umbrella coverages. Most insurance programs are provided on a guaranteed cost basis; however, CNA also offers specialized loss-sensitive insurance programs to those customers viewed as higher risk and less predictable in exposure.

These property and casualty products are offered as part of CNA’s Small Business, Commercial and International insurance groups. CNA’s Small Business insurance group serves its smaller commercial accounts and the Commercial insurance group serves CNA’s middle markets and its larger risks. In addition, CNA Commercial provides total risk management services relating to claim and information services to the large commercial insurance marketplace, through a wholly owned subsidiary, CNA ClaimPlus, Inc., a third party administrator. The International insurance group primarily consists of the commercial product lines of CNA’s operations in Europe and Canada. During the fourth quarter of 2011, CNA sold its 50% ownership interest in First Insurance Company of Hawaii (“FICOH”).

Also included in CNA Commercial is CNA Select Risk (“Select Risk”), which includes CNA’s excess and surplus lines coverages. Select Risk provides specialized insurance for selected commercial risks on both an individual customer and program basis. Customers insured by Select Risk are generally viewed as higher risk and less predictable in exposure than those covered by standard insurance markets. Select Risk’s products are distributed throughout the United States through specialist producers, program agents and brokers.

Hardy

In July of 2012, CNA completed the acquisition of Hardy Underwriting Bermuda Limited (“Hardy”), a specialized Lloyd’s of London (“Lloyd’s”) underwriter. Through Lloyd’s Syndicate 382, Hardy underwrites primarily short-tail exposures in the following coverages: Marine & Aviation provides coverage for a variety of large risks including energy, cargo and specie, marine hull and general aviation. Non-Marine Property comprises direct and facultative property, including construction insurance of industrial and commercial risks (heavy industry, general manufacturing and commercial property portfolios), together with residential and small commercial risks. Property Treaty Reinsurance offers catastrophe reinsurance on an excess of loss basis, proportional treaty and excess of loss coverages and crop reinsurance. Specialty Lines offers coverage for a variety of risks including political violence, accident and health and financial institutions.

 

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Life & Group Non-Core

Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. CNA continues to service its existing individual long term care commitments, its payout annuity business and its pension deposit business. CNA also retains a block of group reinsurance and life settlement contracts. These businesses are being managed as a run-off operation. CNA’s group long term care business, while considered non-core, continues to accept new employees in existing groups.

Other

Other primarily includes certain CNA corporate expenses, including interest on CNA corporate debt, and the results of certain property and casualty business in run-off, including CNA Re and asbestos and environmental pollution (“A&EP”). In 2010, CNA ceded substantially all of its legacy A&EP liabilities under the Loss Portfolio Transfer, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

Direct Written Premiums by Geographic Concentration

Set forth below is the distribution of CNA’s direct written premiums by geographic concentration.

 

Year Ended December 31    2012                       2011                       2010        

 

California

     9.5        9.4        9.3  

Texas

     7.4           6.7           6.5     

New York

     7.1           6.7           6.8     

Illinois

     6.5           4.9           4.0     

Florida

     5.8           6.1           6.1     

New Jersey

     3.5           3.5           3.5     

Pennsylvania

     3.4           3.4           3.4     

Canada

     3.0           3.0           2.9     

All other states, countries or political subdivisions

     53.8           56.3           57.5     

 

     100.0        100.0        100.0  

 

Approximately 9.2%, 8.8% and 6.9% of CNA’s direct written premiums were derived from outside of the United States for the years ended December 31, 2012, 2011 and 2010.

Property and Casualty Claim and Claim Adjustment Expenses

The following loss reserve development table illustrates the change over time of reserves established for property and casualty claim and claim adjustment expenses at the end of the preceding ten calendar years for CNA’s property and casualty insurance companies. The table excludes CNA’s life insurance subsidiaries, and as such, the carried reserves will not agree to the Consolidated Financial Statements included under Item 8. The first section shows the reserves as originally reported at the end of the stated year. The second section, reading down, shows the cumulative amounts paid as of the end of successive years with respect to the originally reported reserve liability. The third section, reading down, shows re-estimates of the originally recorded reserves as of the end of each successive year, which is the result of CNA’s property and casualty insurance subsidiaries’ expanded awareness of additional facts and circumstances that pertain to the unsettled claims. The last section compares the latest re-estimated reserves to the reserves originally established, and indicates whether the original reserves were adequate or inadequate to cover the estimated costs of unsettled claims.

 

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The loss reserve development table is cumulative and, therefore, ending balances should not be added since the amount at the end of each calendar year includes activity for both the current and prior years. The development amounts in the table below include the impact of reinsurance commutations, but exclude the impact of the allowance for doubtful accounts on reinsurance receivables.

 

    Schedule of Loss Reserve Development  

 

 
Year Ended December 31   2002     2003     2004     2005     2006     2007     2008     2009     2010(a)     2011     2012(b)   

 

 
(In millions of dollars)                                                                  

Originally reported gross reserves for unpaid claim and claim adjustment expenses

    25,719        31,284        31,204        30,694        29,459        28,415        27,475        26,712        25,412        24,228        24,696    

Originally reported ceded recoverable

    10,490        13,847        13,682        10,438        8,078        6,945        6,213        5,524        6,060        4,967        5,075    

 

 

Originally reported net reserves for unpaid claim and claim adjustment expenses

    15,229        17,437        17,522        20,256        21,381        21,470        21,262        21,188        19,352        19,261        19,621    

 

 

Cumulative net paid as of:

                     

One year later

    5,373        4,382        2,651        3,442        4,436        4,308        3,930        3,762        3,472        4,277          

Two years later

    8,768        6,104        4,963        7,022        7,676        7,127        6,746        6,174        6,504        -          

Three years later

    9,747        7,780        7,825        9,620        9,822        9,102        8,340        8,374        -        -          

Four years later

    10,870        10,085        9,914        11,289        11,312        10,121        9,863        -        -        -          

Five years later

    12,814        11,834        11,261        12,465        11,973        11,262        -        -        -        -          

Six years later

    14,320        12,988        12,226        12,917        12,858        -        -        -        -        -          

Seven years later

    15,291        13,845        12,551        13,680        -        -        -        -        -        -          

Eight years later

    16,022        14,073        13,245        -        -        -        -        -        -        -          

Nine years later

    16,180        14,713        -        -        -        -        -        -        -        -          

Ten years later

    16,754        -        -        -        -        -        -        -        -        -          

Net reserves re-estimated as of:

                     

End of initial year

    15,229        17,437        17,522        20,256        21,381        21,470        21,262        21,188        19,352        19,261        19,621    

One year later

    17,650        17,671        18,513        20,588        21,601        21,463        21,021        20,643        18,923        19,081          

Two years later

    18,248        19,120        19,044        20,975        21,706        21,259        20,472        20,237        18,734        -          

Three years later

    19,814        19,760        19,631        21,408        21,609        20,752        20,014        20,012        -        -          

Four years later

    20,384        20,425        20,212        21,432        21,286        20,350        19,784        -        -        -          

Five years later

    21,076        21,060        20,301        21,326        20,982        20,155        -        -        -        -          

Six years later

    21,769        21,217        20,339        21,060        20,815        -        -        -        -        -          

Seven years later

    21,974        21,381        20,142        20,926        -        -        -        -        -        -          

Eight years later

    22,168        21,199        20,023        -        -        -        -        -        -        -          

Nine years later

    22,016        21,100        -        -        -        -        -        -        -        -          

Ten years later

    21,922        -        -        -        -        -        -        -        -        -          

 

 

Total net (deficiency) redundancy

    (6,693     (3,663     (2,501     (670     566        1,315        1,478        1,176        618        180          

 

 

Reconciliation to gross re-estimated reserves:

                     

Net reserves re-estimated

    21,922        21,100        20,023        20,926        20,815        20,155        19,784        20,012        18,734        19,081          

Re-estimated ceded recoverable

    16,903        15,273        14,131        11,455        9,131        7,728        6,686        6,032        6,536        5,316          

 

 

Total gross re-estimated reserves

    38,825        36,373        34,154        32,381        29,946        27,883        26,470        26,044        25,270        24,397          

 

 

Total gross (deficiency) redundancy

    (13,106     (5,089     (2,950     (1,687     (487     532        1,005        668        142        (169       

 

 

Net (deficiency) redundancy related to:

                     

Asbestos

    (827     (177     (123     (113     (112     (107     (79     -        -        -          

Environmental pollution

    (282     (209     (209     (159     (159     (159     (76     -        -        -          

 

 

Total asbestos and environmental pollution

    (1,109     (386     (332     (272     (271     (266     (155     -        -        -          

Core (Non-asbestos and environmental pollution)

    (5,584     (3,277     (2,169     (398     837        1,581        1,633        1,176        618        180          

 

 

Total net (deficiency) redundancy

    (6,693     (3,663     (2,501     (670     566        1,315        1,478        1,176        618        180          

 

 

 

(a)

Effective January 1, 2010, CNA ceded approximately $1.5 billion of net asbestos and environmental pollution claim and allocated claim adjustment expense reserves relating to its continuing operations under a retroactive reinsurance agreement with an aggregate limit of $4.0 billion, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

(b)

On July 2, 2012, CNA acquired Hardy. As a result of this acquisition, net reserves were increased by $291 million. Further information on this acquisition is included in Note 2 of the Notes to Consolidated Financial Statements included under Item 8.

 

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Please read information relating to CNA’s property and casualty claim and claim adjustment expense reserves and reserve development set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), and in Notes 1 and 8 of the Notes to Consolidated Financial Statements, included under Item 8.

Investments

Please read Item 7, MD&A – Investments and Notes 1, 3, 4 and 5 of the Notes to Consolidated Financial Statements, included under Item 8.

Other

Competition:  The property and casualty insurance industry is highly competitive both as to rate and service. CNA competes with a large number of stock and mutual insurance companies and other entities for both distributors and customers. Insurers compete on the basis of factors including products, price, services, ratings and financial strength. CNA must continuously allocate resources to refine and improve its insurance products and services.

There are approximately 2,800 individual companies that sell property and casualty insurance in the United States. Based on 2011 statutory net written premiums, CNA is the seventh largest commercial insurance writer and the 13th largest property and casualty insurance organization in the United States.

Regulation:  The insurance industry is subject to comprehensive and detailed regulation and supervision. Each domestic and foreign jurisdiction has established supervisory agencies with broad administrative powers relative to licensing insurers and agents, approving policy forms, establishing reserve requirements, prescribing the form and content of statutory financial reports, and regulating capital adequacy and the type, quality and amount of investments permitted. Such regulatory powers also extend to premium rate regulations, which require that rates not be excessive, inadequate or unfairly discriminatory. In addition to regulation of dividends by insurance subsidiaries, intercompany transfers of assets may be subject to prior notice or approval by insurance regulators, depending on the size of such transfers and payments in relation to the financial position of the insurance subsidiaries making the transfer or payment.

Hardy is also supervised by the Council of Lloyd’s, which is the franchisor for all Lloyd’s operations. The Council of Lloyd’s has wide discretionary powers to regulate Lloyd’s underwriting, such as establishing the capital requirements for syndicate participation. In addition, the annual business plans of each syndicate are subject to the review and approval of the Lloyd’s Franchise Board, which is responsible for business planning and monitoring for all syndicates.

The European Union’s executive body, the European Commission, is implementing new capital adequacy and risk management regulations called Solvency II that would apply to CNA’s European operations. In addition, global regulators, including the United States National Association of Insurance Commissioners, are working with the International Association of Insurance Supervisors (“IAIS”) to consider changes to insurance company supervision. Among the areas being addressed are company and group capital requirements, group supervision and enterprise risk management. It is not currently clear to what extent or how the activities of the IAIS will impact CNA or U.S. insurance regulation.

Domestic insurers are also required by the state insurance regulators to provide coverage to insureds who would not otherwise be considered eligible by the insurers. Each state dictates the types of insurance and the level of coverage that must be provided to such involuntary risks. CNA’s share of these involuntary risks is mandatory and generally a function of its respective share of the voluntary market by line of insurance in each state.

Further, insurance companies are subject to state guaranty fund and other insurance-related assessments. Guaranty fund assessments are levied by the state departments of insurance to cover claims of insolvent insurers. Other insurance-related assessments are generally levied by state agencies to fund various organizations including disaster relief funds, rating bureaus, insurance departments, and workers’ compensation second injury funds, or by industry organizations that assist in the statistical analysis and ratemaking process.

 

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Although the federal government does not directly regulate the business of insurance, federal legislative and regulatory initiatives can impact the insurance industry in a variety of ways. These initiatives and legislation include tort reform proposals; proposals addressing natural catastrophe exposures; terrorism risk mechanisms; federal financial services reforms; various tax proposals affecting insurance companies; and possible regulatory limitations, impositions and restrictions arising from the Dodd-Frank Wall Street Reform and Consumer Protection Act, as well as the Patient Protection and Affordable Care Act, both enacted in 2010.

Various legislative and regulatory efforts to reform the tort liability system have, and will continue to, impact CNA’s industry. Although there has been some tort reform with positive impact to the insurance industry, new causes of action and theories of damages continue to be proposed in state court actions or by federal or state legislatures that continue to expand liability for insurers and their policyholders. For example, some state legislatures have from time to time considered legislation addressing direct actions against insurers related to bad faith claims. As a result of this unpredictability in the law, insurance underwriting is expected to continue to be difficult in commercial lines, professional liability and other specialty coverages.

The Dodd-Frank Wall Street Reform and Consumer Protection Act expanded the federal presence in insurance oversight and may increase the regulatory requirements to which CNA may be subject. The Act’s requirements include streamlining the state-based regulation of reinsurance and nonadmitted insurance (property or casualty insurance placed from insurers that are eligible to accept insurance, but are not licensed to write insurance in a particular state). The Act also established a new Federal Insurance Office within the U.S. Department of the Treasury. The Act called for numerous studies and contemplates further regulation.

The Patient Protection and Affordable Care Act and the related amendments in the Health Care and Education Reconciliation Act may increase CNA’s operating costs and underwriting losses. This landmark legislation may lead to numerous changes in the health care industry that could create additional operating costs for CNA, particularly with respect to its workers’ compensation and long term care products.

Properties:  The Chicago location houses CNA’s principal executive offices. CNA’s subsidiaries own or lease office space in various cities throughout the United States and in other countries. The following table sets forth certain information with respect to CNA’s principal office locations:

 

Location    Size
(square feet)
            Principal Usage

 

333 S. Wabash Avenue
Chicago, Illinois

     732,332              

Principal executive offices of CNA

401 Penn Street
Reading, Pennsylvania

     169,941              

Property and casualty insurance offices

2405 Lucien Way
Maitland, Florida

     111,724              

Property and casualty insurance offices

125 S. Broad Street
New York, New York

     68,935              

Property and casualty insurance offices

101 S. Reid Street
Sioux Falls, South Dakota

     64,789              

Property and casualty insurance offices

4150 N. Drinkwater Boulevard
Scottsdale, Arizona

     56,281              

Property and casualty insurance offices

600 N. Pearl Street
Dallas, Texas

     50,088              

Property and casualty insurance offices

675 Placentia Avenue
Brea, California

     49,957              

Property and casualty insurance offices

4267 Meridian Parkway
Aurora, Illinois

     46,903              

Data center

10375 Park Meadows Drive
Littleton, Colorado

     41,706              

Property and casualty insurance offices

 

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CNA leases its office space described above except for the buildings in Chicago, Illinois, Reading, Pennsylvania and Aurora, Illinois, which are owned.

DIAMOND OFFSHORE DRILLING, INC.

Diamond Offshore Drilling, Inc. (“Diamond Offshore”) is engaged, through its subsidiaries, in the business of operating drilling rigs that are chartered on a contract basis for fixed terms by companies engaged in the exploration and production of hydrocarbons. Offshore rigs are mobile units that can be relocated based on market demand. Diamond Offshore accounted for 21.1%, 23.6% and 23.0% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

Rigs:  Diamond Offshore owns 44 offshore drilling rigs, consisting of 32 semisubmersible rigs, seven jack-ups and five dynamically positioned drillships, four of which are under construction with deliveries scheduled for the second and fourth quarters of 2013 and the second and fourth quarters of 2014. Diamond Offshore’s semisubmersible fleet also includes the Ocean Onyx and Ocean Apex, two moored semisubmersible rigs which are under construction and expected to be delivered in the third quarter of 2013 and the second quarter of 2014. Diamond Offshore’s diverse fleet enables it to offer a broad range of services worldwide in both the floater market (ultra-deepwater, deepwater and mid-water) and the non-floater, or jack-up market.

A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersible rigs hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic positioning (“DP”) to keep the rig on location, or with anchors tethered to the seabed. Although DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats; non-DP, or moored, semisubmersible rigs require tug boats or the use of a heavy lift vessel to move between locations.

A drillship is an adaptation of a maritime vessel which is designed and constructed to carry out drilling operations by means of a substructure with a moon pool centrally located in the hull. Drillships are typically self-propelled and are positioned over a drillsite through the use of either an anchoring system or a DP system similar to those used on semisubmersible rigs.

Diamond Offshore’s floater fleet (semisubmersibles and drillships) can be further categorized based on the nominal water depth for each class of rig as follows:

 

Category   Rated Water Depth (a) (in feet)   Number of Units in Fleet

 

Ultra-Deepwater

  7,501   to   12,000               12 (b)

Deepwater

  5,000   to     7,500                 7 (c)

Mid-Water

     400   to     4,999               18 (d)

 

(a)

Rated water depth for semisubmersibles and drillships reflects the maximum water depth in which a floating rig has been designed to operate. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on conditions (such as salinity of the ocean, weather and sea conditions).

(b)

Includes four drillships under construction.

(c)

Includes two rigs to be constructed utilizing the hulls of two of Diamond Offshore’s existing mid-water floaters.

(d)

Includes three rigs which are being marketed for sale.

Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor. Diamond Offshore’s jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is able to operate is principally determined by the length of the rig’s legs. The rig hull includes the drilling equipment, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until they are firm and stable, and resistance is sufficient to elevate the hull above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the

 

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water and then the legs are retracted for relocation to another drillsite. All of Diamond Offshore’s jack-up rigs are equipped with a cantilever system that enables the rig to extend its drilling package over the aft end of the rig.

Fleet Enhancements and Additions:   Diamond Offshore’s long term strategy is to upgrade its fleet to meet customer demand for advanced, efficient and high-tech rigs by acquiring or building new rigs when possible to do so at attractive prices, and otherwise by enhancing the capabilities of its existing rigs at a lower cost and reduced construction period than newbuild construction would require. Diamond Offshore has contracted with Hyundai Heavy Industries Co. Ltd., for the construction of four dynamically positioned, ultra-deepwater drillships. Diamond Offshore expects the aggregate cost for the four drillships, including commissioning, spares and project management costs, to be approximately $2.6 billion.

Construction has begun on two moored semisubmersible rigs designed to operate in water depths up to 6,000 feet. The rigs will be constructed utilizing the hulls of two of Diamond Offshore’s mid-water floaters and the aggregate cost of the two rigs is estimated to be approximately $680 million, including commissioning, spares and project management costs.

In February of 2013, Diamond Offshore announced that one of its mid-water floaters, the Ocean Patriot, will undergo enhancements to enable the rig to work in the North Sea at an estimated aggregate cost of approximately $120 million. The enhancement project is expected to begin during the third quarter of 2013 with completion expected in early 2014.

Diamond Offshore will evaluate further rig acquisition and upgrade opportunities as they arise. However, Diamond Offshore can provide no assurance whether, or to what extent, it will continue to make rig acquisitions or upgrades to its fleet.

Markets:  The principal markets for Diamond Offshore’s contract drilling services are the following:

 

   

South America, principally offshore Brazil;

 

   

Australia and Asia, including Malaysia, Indonesia, Thailand and Vietnam;

 

   

the Middle East, including Kuwait, Qatar and Saudi Arabia;

 

   

Europe, principally in the United Kingdom (“U.K.”) and Norway;

 

   

East and West Africa;

 

   

the Mediterranean Basin, including Egypt; and

 

   

the Gulf of Mexico, including the U.S. and Mexico.

Diamond Offshore actively markets its rigs worldwide. From time to time Diamond Offshore’s fleet operates in various other markets throughout the world.

Diamond Offshore believes its presence in multiple markets is valuable in many respects. For example, Diamond Offshore believes that its experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and other international areas in which Diamond Offshore operates, while production experience it has gained through its Brazilian and North Sea operations has potential application worldwide. Additionally, Diamond Offshore believes its performance for a customer in one market area enables it to better understand that customer’s needs and better serve that customer in different market areas or other geographic locations.

Drilling Contracts:  Diamond Offshore’s contracts to provide offshore drilling services vary in their terms and provisions. Diamond Offshore typically obtains its contracts through a competitive bid process, although it is not unusual for Diamond Offshore to be awarded drilling contracts following direct negotiations. Drilling contracts generally provide for a basic fixed dayrate regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for reductions in rates during periods when the rig is being moved or when

 

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drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other circumstances. Under dayrate contracts, Diamond Offshore generally pays the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of Diamond Offshore’s revenues. In addition, from time to time, Diamond Offshore’s dayrate contracts may also provide for the ability to earn an incentive bonus from its customer based upon performance.

The duration of a dayrate drilling contract is generally tied to the time required to drill a single well or a group of wells, which Diamond Offshore refers to as a well-to-well contract, or a fixed period of time, in what Diamond Offshore refers to as a term contract. Many drilling contracts may be terminated by the customer in the event the drilling rig is destroyed or lost or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party to the contract. Certain of Diamond Offshore’s contracts also permit the customer to terminate the contract early by giving notice, and in most circumstances, this requires the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension.

Customers:   Diamond Offshore provides offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2012, 2011 and 2010, Diamond Offshore performed services for 35, 52 and 46 different customers. During 2012, 2011 and 2010, one of Diamond Offshore’s customers in Brazil, Petróleo Brasileiro S.A. (“Petrobras”), (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for 33%, 35% and 24% of Diamond Offshore’s annual total consolidated revenues. OGX Petróleo e Gás Ltda. (“OGX”), (a privately owned Brazilian oil and natural gas company), accounted for 12%, 14% and 14% of Diamond Offshore’s annual total consolidated revenues in each of the years ended December 31, 2012, 2011 and 2010. No other customer accounted for 10% or more of Diamond Offshore’s annual total consolidated revenues during 2012, 2011 or 2010.

Brazil is one of the most active floater markets in the world today. Currently, the greatest concentration of Diamond Offshore’s operating assets is offshore Brazil, where it has 12 rigs contracted. Diamond Offshore’s contract backlog attributable to its expected operations offshore Brazil is $1.2 billion, $1.0 billion, $0.5 billion and $62 million for the years 2013, 2014, 2015 and 2016.

Competition:   Despite consolidation in recent years, the offshore contract drilling industry remains highly competitive with numerous industry participants, none of which at the present time has a dominant market share. The industry may also experience additional consolidation in the future, which could create other large competitors. Some of Diamond Offshore’s competitors may have greater financial or other resources than Diamond Offshore. Diamond Offshore competes with offshore drilling contractors that together have almost 780 mobile rigs available worldwide.

The offshore contract drilling industry is influenced by a number of factors, including global economies and demand for oil and natural gas, current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs.

Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. Diamond Offshore believes it competes favorably with respect to these factors.

Diamond Offshore competes on a worldwide basis, but competition may vary significantly by region at any particular time. Competition for offshore rigs generally takes place on a global basis, as these rigs are highly mobile and may be moved, at a cost that may be substantial, from one region to another. It is characteristic of the offshore contract drilling industry to move rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling units could also intensify price competition.

 

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Governmental Regulation:  Diamond Offshore’s operations are subject to numerous international, foreign, U.S., state and local laws and regulations that relate directly or indirectly to its operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use.

Operations Outside the United States:  Diamond Offshore’s operations outside the U.S. accounted for approximately 94%, 90% and 81% of its total consolidated revenues for the years ended December 31, 2012, 2011 and 2010.

Properties:   Diamond Offshore owns an office building in Houston, Texas, where its corporate headquarters are located, offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil and Ciudad del Carmen, Mexico. Additionally, Diamond Offshore currently leases various office, warehouse and storage facilities in Louisiana, Australia, Indonesia, Norway, Malaysia, Singapore, Egypt, Equatorial Guinea, Angola, Vietnam and the U.K. to support its offshore drilling operations.

BOARDWALK PIPELINE PARTNERS, LP

Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”) is engaged in integrated natural gas and natural gas liquids (“NGLs”) transportation and storage and natural gas gathering and processing. Boardwalk Pipeline accounted for 8.1%, 8.1% and 7.7% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

We own approximately 55% of Boardwalk Pipeline comprised of 102,719,466 common units, 22,866,667 class B units and a 2% general partner interest. A wholly owned subsidiary of ours, Boardwalk Pipelines Holding Corp. (“BPHC”) is the general partner and holds all of Boardwalk Pipeline’s incentive distribution rights which entitle the general partner to an increasing percentage of the cash that is distributed by Boardwalk Pipeline in excess of $0.4025 per unit per quarter.

In October of 2012, Boardwalk Pipeline acquired Boardwalk Louisiana Midstream LLC (“Louisiana Midstream”) for approximately $620 million. Louisiana Midstream provides transportation and storage services for natural gas and NGLs, fractionation services for NGLs and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana.

Boardwalk Pipeline owns and operates approximately 14,170 miles of interconnected natural gas pipelines directly serving customers in 13 states and indirectly serving customers throughout the northeastern and southeastern United States through numerous interconnections with unaffiliated pipelines. Boardwalk Pipeline also owns approximately 240 miles of NGL pipelines in Louisiana. In 2012, its pipeline systems transported approximately 2.5 trillion cubic feet (“Tcf”) of gas and approximately 7.1 million barrels (“MMbbls”) of NGLs. Average daily throughput on Boardwalk Pipeline’s natural gas pipeline systems during 2012 was approximately 6.9 billion cubic feet (“Bcf”). Boardwalk Pipeline’s natural gas storage facilities are comprised of 14 underground storage fields located in four states with aggregate working gas capacity of approximately 201.0 Bcf and Boardwalk Pipeline’s NGL storage facilities consist of eight salt dome storage caverns located in one state with an aggregate storage capacity of approximately 17.6 MMbbls. Boardwalk Pipeline also owns two salt dome caverns for use in providing brine supply services and to support the NGL cavern operations.

The pipeline and storage systems of Boardwalk Pipeline consist of the following:

The Gulf Crossing pipeline system, which originates in Texas and proceeds into Louisiana, operates approximately 360 miles of natural gas pipeline. The pipeline system has a peak-day delivery capacity of 1.7 Bcf per day and average daily throughput for the year ended December 31, 2012 was 1.3 Bcf per day.

The Gulf South pipeline system runs approximately 7,240 miles along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. Gulf South has two natural gas storage facilities with 83.0 Bcf of working gas storage capacity. The pipeline system has a peak-day delivery capacity of 6.8 Bcf per day and average daily throughput for the year ended December 31, 2012 was 3.0 Bcf per day.

 

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The Texas Gas pipeline system originates in Louisiana, East Texas and Arkansas and runs for approximately 6,110 miles north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and into Ohio, with smaller diameter lines extending into Illinois. The pipeline system has a peak-day delivery capacity of 4.4 Bcf per day and average daily throughput for the year ended December 31, 2012 was 2.5 Bcf per day. Texas Gas owns nine natural gas storage fields with 84.0 Bcf of working gas storage capacity.

Field Services operates natural gas gathering, compression, treating and processing infrastructure in southern Texas and in the Marcellus Shale area in Pennsylvania with approximately 355 miles of pipeline.

Boardwalk HP Storage Company, LLC (“HP Storage”) owns and operates seven salt dome natural gas storage caverns in Mississippi, with 36.3 Bcf of total storage capacity, of which approximately 23.0 Bcf is working gas capacity. HP Storage also operates approximately 105 miles of pipeline which connects its facilities with several major natural gas pipelines, including Gulf South. Average daily throughput for the pipeline system for the year ended December 31, 2012 was 0.1 Bcf per day. HP Storage also owns undeveloped land which is suitable for up to six additional storage caverns, one of which is expected to be placed in service in 2013.

Louisiana Midstream’s storage services provide approximately 53.2 MMbbls of salt dome storage capacity, including approximately 11.0 Bcf of working natural gas storage capacity and approximately 17.6 MMbbls of salt dome NGL storage capacity, significant brine supply infrastructure including two salt dome caverns and more than 240 miles of pipeline assets, including an extensive ethylene distribution system.

Boardwalk Pipeline’s current expansion projects include the following:

Southeast Market Expansion: The Southeast Market Expansion project is an interconnection between Boardwalk Pipeline’s Gulf South pipeline and HP Storage facilities, additional compression facilities and approximately 70 miles of additional pipeline, adding 0.5 Bcf per day of peak-day transmission capacity, subject to Federal Energy Regulatory Commission (“FERC”) approval. The project is expected to be placed in service in the second half of 2014 and will cost approximately $300 million. The Southeast Market Expansion project is fully contracted with a weighted-average contract life of approximately 10 years.

South Texas Eagle Ford Expansion: The South Texas Eagle Ford Expansion construction project consists of 55 miles of gathering pipeline and a cryogenic processing plant. The system will have the capability of gathering in excess of 0.3 Bcf per day of liquids-rich gas in the Eagle Ford Shale production area in Texas and processing up to 150 MMcf per day of liquids-rich gas. Boardwalk Pipeline will also provide re-delivery of processed residue gas to a number of interstate and intrastate pipelines. Boardwalk Pipeline has executed long term fee-based gathering and processing agreements for approximately 50% of the plant’s processing capacity. The plant and new pipeline are estimated to cost approximately $180 million and are expected to be placed in service in April of 2013.

Salt Dome Storage: HP Storage is developing a new salt dome storage cavern having working gas capacity of approximately 5.3 Bcf, which is expected to be placed in service in the second quarter of 2013 with an estimated cost of approximately $23 million.

Choctaw Brine Supply Expansion Projects: Louisiana Midstream is engaged in two brine supply service expansion projects. The first brine supply project consists of the development of a one million barrel brine pond, which was placed in service in January of 2013 at a total cost of approximately $13 million. Louisiana Midstream has executed seven-year, fixed-fee contracts in support of this project. The second project, which is supported by a 20-year commitment with minimum volume requirements, consists of constructing 26 miles of 12-inch pipeline from Louisiana Midstream’s facilities to a petrochemical customer’s plant. This project is expected to cost approximately $50 million and is expected to be placed in service in the third quarter of 2013.

Customers:  Boardwalk Pipeline serves a broad mix of customers, including producers of natural gas, local distribution companies, marketers, electric power generators, industrial users and interstate and intrastate pipelines, located throughout the Gulf Coast, Midwest and Northeast regions of the U.S.

 

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Competition:   Boardwalk Pipeline competes with numerous other pipelines that provide transportation, storage and other services at many locations along its pipeline systems. Boardwalk Pipeline also competes with pipelines that are attached to new natural gas supply sources that are being developed closer to some of its traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of Boardwalk Pipeline’s traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with Boardwalk Pipeline’s natural gas pipeline services. Further, natural gas competes with other forms of energy available to Boardwalk Pipeline’s customers, including electricity, coal, fuel oils and alternative fuel sources.

The principal elements of competition among pipelines are available capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors. This is especially the case with capacity being sold on a longer term basis. Boardwalk Pipeline is focused on finding opportunities to enhance its competitive profile in these areas by increasing the flexibility of its pipeline systems to meet the demands of customers, such as power generators and industrial users, and is continually reviewing its services and terms of service to offer customers enhanced service options.

Seasonality:   Boardwalk Pipeline’s revenues can be affected by weather, natural gas price levels and natural gas price volatility. Weather impacts natural gas demand for heating needs and power generation, which in turn influences the short term value of transportation and storage across Boardwalk Pipeline’s pipeline systems. Colder than normal winters can result in an increase in the demand for natural gas for heating needs and warmer than normal summers can impact cooling needs, both of which typically result in increased pipeline transportation revenues and throughput. While traditionally peak demand for natural gas occurs during the winter months driven by heating needs, the increased use of natural gas for cooling needs during the summer months has partially reduced the seasonality of revenues. In 2012, approximately 53% of Boardwalk Pipeline’s revenue was recognized in the first and fourth quarters of the year.

Governmental Regulation:   FERC regulates Boardwalk Pipeline’s natural gas operating subsidiaries under the Natural Gas Act (“NGA”) of 1938 and the Natural Gas Policy Act (“NGPA”) of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, Boardwalk Pipeline’s natural gas interstate subsidiaries hold certificates of public convenience and necessity issued by FERC covering certain of their facilities, activities and services. The maximum rates that may be charged by Boardwalk Pipeline’s subsidiaries operating under FERC’s jurisdiction, for all aspects of the natural gas transportation services it provides, are established through FERC’s cost-of-service rate-making process. The maximum rates that may be charged by Boardwalk Pipeline for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized Boardwalk Pipeline to charge market-based rates for its firm and interruptible storage services for the majority of its storage facilities. None of Boardwalk Pipeline’s FERC-regulated entities has an obligation to file a new rate case.

Boardwalk Pipeline is also regulated by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (“NGPSA”) and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas and NGL pipeline facilities. Boardwalk Pipeline has received authority from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of DOT, to operate certain natural gas pipeline assets under special permits that will allow it to operate those assets at higher than normal operating pressures of up to 0.80 of the pipe’s Specified Minimum Yield Strength (“SMYS”). Operating at higher than normal operating pressures will allow each of these pipelines to transport all of the volumes Boardwalk Pipeline has contracted for with its customers. PHMSA retains discretion whether to grant or maintain authority for Boardwalk Pipeline to operate these natural gas pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along their pipelines and take additional measures to protect pipeline

 

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segments located in highly populated areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Act”) was enacted in 2012 and increased maximum civil penalties for certain violations to $200,000 per violation per day, and from a total cap of $1 million to $2 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

Boardwalk Pipeline’s operations are also subject to extensive federal, state, and local laws and regulations relating to protection of the environment. Such regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental regulations also require that Boardwalk Pipeline’s facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.

Properties:  Boardwalk Pipeline is headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. Boardwalk Pipeline also leases approximately 108,000 square feet of office space in Owensboro, Kentucky. Boardwalk Pipeline’s operating subsidiaries own their respective pipeline systems in fee. However, substantial portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents.

HIGHMOUNT EXPLORATION & PRODUCTION LLC

HighMount Exploration & Production, LLC (“HighMount”) is engaged in the exploration, production and marketing of natural gas and oil (including condensate and NGLs). HighMount accounted for 2.0%, 2.5% and 2.9% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010.

HighMount’s proved reserves and production are primarily located in the Sonora field, a tight sands gas formation within the Permian Basin in West Texas. HighMount holds mineral rights on over 500,000 net acres in the Permian Basin, with over 6,000 producing wells. In addition, HighMount has working interests in undeveloped oil and gas properties located on approximately 73,000 net acres in Oklahoma and approximately 9,000 net acres in the Texas Panhandle which contain primarily oil reserves. During 2012, HighMount began the commercial development of its Oklahoma properties, utilizing horizontal drilling and hydraulic fracturing technologies.

HighMount’s interests in developed and undeveloped acreage, wellbores and well facilities generally take the form of working interests in leases that have varying terms. HighMount’s interests in these properties are, in many cases, held jointly with third parties and may be subject to royalty, overriding royalty, carried, net profits and other similar interests and contractual arrangements with other parties as is customary in the oil and gas industry. HighMount also owns and operates approximately 3,000 miles of gathering lines and over 65,000 horsepower of compression which are used to transport natural gas and NGLs principally from HighMount’s producing wells to processing plants and pipelines owned by third parties.

 

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We use the following terms throughout this discussion of HighMount’s business, with “equivalent” volumes computed with oil and NGL quantities converted to Mcf, on an energy equivalent ratio of one barrel to six Mcf:

 

Average price  

-

 

Average price during the twelve-month period, prior to the date of the estimate, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements with customers, excluding escalations based upon future conditions

Bbl  

-

 

Barrel (of oil or NGLs)

Bcf  

-

 

Billion cubic feet (of natural gas)

Bcfe  

-

 

Billion cubic feet of natural gas equivalent

Developed acreage  

-

 

Acreage assignable to productive wells

Gross acres  

-

 

Total acres in which HighMount owns a working interest

Gross wells  

-

 

Total number of wells in which HighMount owns a working interest

Mcf  

-

 

Thousand cubic feet (of natural gas)

Mcfe  

-

 

Thousand cubic feet of natural gas equivalent

MMBbl  

-

 

Million barrels (of oil or NGLs)

MMBtu  

-

 

Million British thermal units

MMcf  

-

 

Million cubic feet (of natural gas)

MMcfe  

-

 

Million cubic feet of natural gas equivalent

Net acres  

-

 

The sum of all gross acres covered by a lease or other arrangement multiplied by the working interest owned by HighMount in such gross acreage

Net wells  

-

 

The sum of all gross wells multiplied by the working interest owned by HighMount in such wells

NGL  

-

 

Natural Gas Liquids – largely ethane and propane as well as some heavier hydrocarbons

Productive wells  

-

 

Producing wells and wells mechanically capable of production

Proved reserves  

-

 

Quantities of natural gas, NGLs and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations

Proved developed reserves  

-

 

Proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods

Proved undeveloped reserves  

-

 

Proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required

Tcf  

-

 

Trillion cubic feet (of natural gas)

Tcfe  

-

 

Trillion cubic feet of natural gas equivalent

Undeveloped acreage  

-

 

Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas

As of December 31, 2012, HighMount owned 825.1 Bcfe of net proved reserves, of which 84.1% were classified as proved developed reserves. HighMount’s estimated total proved reserves consist of 557.6 Bcf of natural gas, 35.1 MMBbls of NGLs, and 9.5 MMBbls of oil and condensate. HighMount produced approximately 154 MMcfe per day of net natural gas, NGLs and oil during 2012. HighMount holds leasehold or drilling rights in 0.7 million net acres, of which 0.5 million is developed acreage and the balance is held for future exploration and development drilling opportunities. HighMount participated in the drilling of 91 wells during 2012, of which 83 (or 91.2%) are productive wells.

Reserves:  HighMount’s reserves represent its share of reserves based on its net revenue interest in each property. Estimated reserves as of December 31, 2012 are based upon studies for each of HighMount’s properties prepared by HighMount staff engineers and are the responsibility of management. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with Securities and Exchange Commission (“SEC”) guidelines.

 

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HighMount employs various internal controls to validate the reserve estimation process. The main internal controls include (i) detailed reviews of reserve-related information by reserve engineering and executive management, (ii) reserve audits performed by an independent third party reserve auditor, (iii) segregation of duties, and (iv) system reconciliation or automated interface between various systems used in the reserve estimation process.

HighMount employs a team of reservoir engineers that specialize in HighMount’s areas of operation. The reservoir engineering team reports to HighMount’s Chief Operating Officer. The compensation of HighMount’s reservoir engineers is not dependent on the quantity of reserves booked. HighMount also employs a lead evaluator who reports to the Chief Financial Officer. HighMount’s lead evaluator has over 33 years of petroleum engineering experience, most of which have been in the reservoir engineering and reserve fields. He is a member in good standing of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers, as well as a Licensed Professional Engineer in the State of Texas.

HighMount’s reserves estimates for 2012 have been independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and governmental agencies. NSAI was founded in 1961 and performs consulting services under Texas Board of Professional Engineers Registration No. F-2699. The technical person primarily responsible for NSAI’s audit and audit letter has 32 years of industry experience and has been practicing consulting petroleum engineering at NSAI since 1989.

The following table sets forth HighMount’s proved reserves at December 31, 2012, based on average 2012 prices of $2.76 per MMBtu for natural gas, $41.11 per Bbl for NGLs and $94.71 per Bbl for oil. Approximately 95% of HighMount’s proved reserves were located in the Permian Basin in Texas and approximately 5% of proved reserves were located in Oklahoma.

 

         Natural Gas    
(MMcf)
    

    NGLs    

(Bbls)

    

Oil  

(Bbls)  

      Natural Gas 
Equivalents
(MMcfe)
 

 

    

 

 

 

Proved developed

     490,978                28,835,347           4,945,283             693,662      

Proved undeveloped

     66,577                6,263,323           4,546,590             131,436      

 

    

 

 

 

Total proved

     557,555                    35,098,670               9,491,873             825,098      

 

    

 

 

 

HighMount reviews its proved reserves on an annual basis. During 2012, total proved reserves declined 309 Bcfe, reflecting (i) a 328 Bcfe reduction as a result of economic factors such as lower gas prices and higher operating expenses, and as a result of higher production decline rates of its producing wells, partly due to the suspension of uneconomic maintenance and recompletion work, (ii) a 56 Bcfe reduction as a result of production during the year, offset by (iii) additions of 75 Bcfe through drilling and booking of proved undeveloped locations.

At December 31, 2012, HighMount had proved undeveloped reserves of 131 Bcfe on locations scheduled to be drilled in the next five years. During 2012, HighMount recorded negative net reserve revisions of 198 Bcfe primarily due to a reclassification of proved undeveloped reserves to the non-proved category because these reserves were no longer economical due to the decrease in natural gas prices. Also, 48 Bcfe of non-proved reserves were promoted to the proved undeveloped category as a result of the 2012 drilling activity. During 2012, HighMount spent $14 million to convert 2 Bcfe from proved undeveloped reserves to proved developed reserves through drilling. As of December 31, 2012, there were no proved undeveloped locations that had remained undeveloped for five years or more.

Estimated net quantities of proved natural gas and oil reserves at December 31, 2012, 2011 and 2010 and changes in the reserves during 2012, 2011 and 2010 are shown in Note 14 of the Notes to Consolidated Financial Statements included under Item 8.

HighMount’s Sonora properties typically have relatively long reserve lives and high well completion success rates. Based on December 31, 2012 proved reserves and HighMount’s average production from these properties during 2012, the average reserve-to-production index of HighMount’s proved reserves is 15 years.

 

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In order to replenish reserves as they are depleted by production, and to increase reserves, HighMount develops its existing acreage by drilling new wells and, where available, employing new technologies and drilling strategies designed to enhance production from existing wells. In addition, HighMount seeks to acquire additional acreage in its core areas of operation, as well as other locations where its management has identified an opportunity.

During 2012, 2011 and 2010, HighMount engaged in the drilling activity presented in the following table:

 

Year Ended December 31    2012          2011          2010           

 

     Gross                 Net               Gross                 Net              Gross                 Net         

 

Development Wells

                                

Productive Wells

     83             78.5            46            46.0            227             221.3      

Dry Wells

     8             8.0                      5.0            11             11.0      

 

Total Development Wells

     91             86.5            51            51.0            238             232.3      

 

Exploratory Wells

                                

Productive Wells

                10            9.5                 

Dry Wells

                          2.0            2             2.0      

 

Total Exploratory Wells

                12            11.5            2             2.0      

 

Total Completed Wells

     91             86.5            63            62.5            240             234.3      

 

In addition, at December 31, 2012, HighMount had 23 (20.2 net) wells in progress.

Acreage:  As of December 31, 2012, HighMount owned interests in 1,107,551 gross (700,281 net) acres in the United States which is comprised of 609,659 gross (467,602 net) developed acres, and 497,892 gross (232,679 net) undeveloped acres.

As of December 31, 2012, leases covering 86,577, 27,859 and 9,843 of HighMount’s net acreage will expire by December 31, 2013, 2014 and 2015, if production is not established or HighMount takes no other action to extend the terms.

Production and Sales:  Please see the Production and Sales statistics table for additional information included in the MD&A under Item 7.

HighMount utilizes its own marketing and sales personnel to market the natural gas and oil that it produces to large energy companies and intrastate pipelines and gathering companies. Production is typically sold and delivered directly to a pipeline at liquid pooling points or at the tailgates of various processing plants, where it then enters a pipeline system. Permian Basin natural gas sales prices are primarily at a Houston Ship Channel Index.

To manage the risk of fluctuations in prevailing commodity prices, HighMount enters into commodity and basis swaps and other derivative instruments.

Wells:  As of December 31, 2012, HighMount had working interests in 6,133 gross producing wells (5,874 net producing wells) located primarily in the Permian Basin. In addition, HighMount had royalty interests in approximately 250 wells located in the Permian Basin. Wells located in the Permian Basin have a typical well depth in the range of 6,000 to 9,000 feet.

Competition:  HighMount competes with other oil and gas companies in all aspects of its business, including acquisition of producing properties and leases and obtaining goods, services and labor, including drilling rigs and well completion services. HighMount also competes in the marketing of produced natural gas and oil. Some of HighMount’s competitors have substantially larger financial and other resources than HighMount. Factors that affect HighMount’s ability to acquire producing properties include available funds, available information about the property and standards established by HighMount for minimum projected return on investment. Natural gas and oil also compete with alternative fuel sources, including heating oil and coal.

 

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Governmental Regulation:  All of HighMount’s operations are conducted onshore in the United States. The U.S. oil and gas industry, and HighMount’s operations, are subject to regulation at the federal, state and local level. Such regulation includes requirements with respect to, among other things: permits to drill and to conduct other operations; provision of financial assurances (such as bonds) covering drilling and well operations; the location of wells; the method of drilling and completing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; the marketing, transportation and reporting of production; the valuation and payment of royalties; the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area); the unitization or pooling of natural gas and oil properties; maximum rates of production from natural gas and oil wells; venting or flaring of natural gas; and the ratability of production and the operation of gathering systems and related assets.

HighMount uses hydraulic fracturing to stimulate the production of oil and natural gas. In recent years, concerns have been raised that the fracturing process may, among other things, contaminate underground sources of drinking water. The conference committee report for The Department of the Interior, Environment, and Related Agencies Appropriations Act for Fiscal Year 2010 requested the United States Environmental Protection Agency (“EPA”) to conduct a study of hydraulic fracturing, particularly the relationship between hydraulic fracturing and drinking water. In December of 2012 the EPA issued a progress report of the projects the EPA is conducting as part of the study. A final draft report is expected to be released for public comment and peer review in 2014. Several bills have been introduced in Congress seeking federal regulation of hydraulic fracturing, which has historically been regulated at the state level, though none of the proposed legislation has been passed into law. HighMount believes that similar bills will continue to be introduced in Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing; however, HighMount cannot predict whether any such bill will be passed into law or, if passed, the substance of any such new law.

The Federal Energy Policy Act of 2005 amended the NGA to prohibit natural gas market manipulation by any entity, directed the FERC to facilitate market transparency in the sale or transportation of physical natural gas and significantly increased the penalties for violations of the NGA of 1938, the NGPA of 1978, or FERC regulations or orders thereunder. In addition, HighMount owns and operates gas gathering lines and related facilities which are regulated by the DOT and state agencies with respect to safety and operating conditions.

HighMount’s operations are also subject to federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, HighMount’s operations may require it to obtain permits for, among other things, air emissions, discharges into surface waters, and the construction and operation of underground injection wells or surface pits to dispose of produced saltwater and other non-hazardous oilfield wastes. HighMount could be required, without regard to fault or the legality of the original disposal, to remove or remediate previously disposed wastes, to suspend or cease operations in contaminated areas or to perform remedial well plugging operations or cleanups to prevent future contamination.

In September of 2009, the EPA adopted regulations under the Clean Air Act requiring the monitoring and reporting of annual greenhouse gas (“GHG”) emissions by certain large U.S. GHG emitters. Affected companies are required to monitor their GHG emissions and report to the EPA. Oil and gas exploration and production companies that emit more than 25,000 metric tons of GHG per year from any facility (as defined in the regulations), including HighMount, are required to monitor and report emissions for facilities that meet the emissions threshold. HighMount filed its first GHG report in September of 2012 for the 2011 reporting year.

Properties:  In addition to its interests in oil and gas producing properties, HighMount leases an aggregate of approximately 56,300 square feet of office space in Houston, Texas, which includes its corporate headquarters, and approximately 83,800 square feet of office space in Oklahoma City, Oklahoma. HighMount also leases other surface rights and office, warehouse and storage facilities necessary to operate its business. In addition to leased properties, HighMount also owns a 44,000 square foot office building in Sonora, Texas, and a 1,500 square foot office building in Morrison, Oklahoma.

 

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LOEWS HOTELS HOLDING CORPORATION

The subsidiaries of Loews Hotels Holding Corporation (“Loews Hotels”), our wholly owned subsidiary, presently operate a chain of 19 primarily upper, upscale hotels. Each hotel in the chain is managed by Loews Hotels. Ten of these hotels are owned by Loews Hotels, five are owned by joint ventures in which Loews Hotels has a significant equity interest and four are managed for unaffiliated owners. Loews Hotels’ earnings are derived from the operation of its wholly owned hotels, its share of earnings in joint venture hotels and hotel management fees earned from both joint venture and managed hotels. Loews Hotels accounted for 2.7%, 2.4% and 2.1% of our consolidated total revenue for the years ended December 31, 2012, 2011 and 2010. The hotels are described below.

 

Name and Location  

      Number of      

Rooms

  

Land Lease Information    

(if applicable)    

 

Owned:

    

Loews Annapolis Hotel, Annapolis, Maryland

     220   

Loews Boston Back Bay Hotel, Boston, Massachusetts

     225   

Loews Coronado Bay, San Diego, California

     440   

Land lease expiring 2034

Loews Le Concorde Hotel, Quebec City, Canada

     405   

Land lease expiring 2069

Loews Madison Hotel, Washington, D.C.

     356   

Loews Miami Beach Hotel, Miami Beach, Florida

     790   

Loews Philadelphia Hotel, Philadelphia, Pennsylvania

     585   

Loews Regency Hotel, New York, New York

     350   

Land lease expiring 2036 with renewal option for 24 years

Loews Vanderbilt Hotel, Nashville, Tennessee

     340   

Loews Hotel Vogue, Montreal, Canada

     140   

Joint Venture/Managed:

    

The Don CeSar, a Loews Hotel, St. Pete Beach, Florida

     347   

Hard Rock Hotel, at Universal Orlando, Orlando, Florida

     650   

Loews Hollywood Hotel, Hollywood, California

     632   

Loews Portofino Bay Hotel, at Universal Orlando, Orlando, Florida

     750   

Loews Royal Pacific Resort at Universal Orlando, Orlando, Florida

  1,000   

Management Contract:

    

Loews Atlanta Hotel, Atlanta, Georgia

     414   

Loews New Orleans Hotel, New Orleans, Louisiana

     285   

Loews Santa Monica Beach Hotel, Santa Monica, California

     340   

Loews Ventana Canyon, Tucson, Arizona

     400   

Competition: Competition from other hotels and lodging facilities is vigorous in all areas in which Loews Hotels operates. The demand for hotel rooms in many areas is seasonal and dependent on general and local economic conditions. Loews Hotels properties also compete with facilities offering similar services in locations other than those in which its hotels are located. Competition among luxury hotels is based primarily on location and service. Competition among resort and commercial hotels is based on price as well as location and service. Because of the competitive nature of the industry, hotels must continually make expenditures for updating, refurnishing and repairs and maintenance, in order to prevent competitive obsolescence.

 

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Recent Developments:

 

   

In June of 2012, Loews Hotels acquired a hotel in Hollywood, California, which is now operating as the Loews Hollywood Hotel. In November of 2012, Loews Hotels formed a joint venture with an institutional investor, which acquired an equity interest in the Loews Hollywood Hotel.

 

   

In December of 2012, Loews Hotels sold the Loews Denver Hotel.

 

   

In January of 2013, Loews Hotels acquired a hotel in Washington, D.C., which is now operating as the Loews Madison Hotel.

 

   

In February of 2013, Loews Hotels acquired a hotel in Boston, Massachusetts, which is now operating as the Loews Boston Back Bay Hotel.

 

   

In 2012, Loews Hotels became a 50% partner in a joint venture which is constructing an 1,800 guestroom hotel at Universal Orlando, Florida.

 

   

In December of 2012, Loews Hotels agreed to purchase, upon completion of development expected to occur in 2015, a 400 guestroom hotel in Chicago, Illinois.

EMPLOYEE RELATIONS

Including our operating subsidiaries as described below, we employed approximately 18,300 persons at December 31, 2012. We, and our subsidiaries, have experienced satisfactory labor relations.

CNA employed approximately 7,500 persons.

Diamond Offshore employed approximately 5,300 persons, including international crew personnel furnished through independent labor contractors.

Boardwalk Pipeline employed approximately 1,200 persons, approximately 110 of whom are union members covered under collective bargaining units.

HighMount employed approximately 400 persons.

Loews Hotels employed approximately 3,625 persons, approximately 965 of whom are union members covered under collective bargaining units.

EXECUTIVE OFFICERS OF THE REGISTRANT

 

Name    Position and Offices Held    Age    First
  Became  
Officer

 

David B. Edelson

  

Senior Vice President

   53    2005

Gary W. Garson

  

Senior Vice President, General Counsel and Secretary

   66    1988

Peter W. Keegan

  

Senior Vice President and Chief Financial Officer

   68    1997

Richard W. Scott

  

Senior Vice President and Chief Investment Officer

   59    2009

Kenneth I. Siegel

  

Senior Vice President

   55    2009

Andrew H. Tisch

  

Office of the President, Co-Chairman of the Board and Chairman of the Executive Committee

   63    1985

James S. Tisch

  

Office of the President, President and Chief Executive Officer

   60    1981

Jonathan M. Tisch

  

Office of the President and Co-Chairman of the Board

   59    1987

 

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Andrew H. Tisch and James S. Tisch are brothers and are cousins of Jonathan M. Tisch. None of the other officers or directors of Registrant is related to any other.

All of our executive officers except for Kenneth I. Siegel and Richard W. Scott have been engaged actively and continuously in our business for more than the past five years. Prior to joining us in 2009, Mr. Siegel was employed as a Managing Director in the Mergers & Acquisitions Department at Barclays Capital Inc. and previously in a similar capacity at Lehman Brothers. Prior to joining us in 2009, Mr. Scott was employed at American International Group, Inc. for more than five years, serving in various senior investment positions, including Chief Investment Officer–Insurance Portfolio Management.

Officers are elected and hold office until their successors are elected and qualified, and are subject to removal by the Board of Directors.

AVAILABLE INFORMATION

Our website address is www.loews.com. We make available, free of charge, through the website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after these reports are electronically filed with or furnished to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee charter, Compensation Committee charter and Nominating and Governance Committee charter have also been posted and are available on our website.

Item 1A.  RISK FACTORS.

Our business faces many risks. We have described below some of the more significant risks which we and our subsidiaries face. There may be additional risks that we do not yet know of or that we do not currently perceive to be significant that may also impact our business or the business of our subsidiaries.

Each of the risks and uncertainties described below could lead to events or circumstances that have a material adverse effect on our business, results of operations, cash flows, financial condition or equity and/or the business, results of operations, financial condition or equity of one or more of our subsidiaries.

You should carefully consider and evaluate all of the information included in this Report and any subsequent reports we may file with the SEC or make available to the public before investing in any securities issued by us. Our subsidiaries, CNA Financial Corporation, Diamond Offshore Drilling, Inc. and Boardwalk Pipeline Partners, LP, are public companies and file reports with the SEC. You are also cautioned to carefully review and consider the information contained in the reports filed by those subsidiaries before investing in any of their securities.

Risks Related to Us and Our Subsidiary, CNA Financial Corporation

If CNA determines that its recorded insurance reserves are insufficient to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, CNA may need to increase its insurance reserves.

CNA maintains insurance reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for reported and unreported claims and for future policy benefits. Reserves represent CNA’s best estimate at a given point in time. Insurance reserves are not an exact calculation of liability but instead are complex estimates derived by CNA, generally utilizing a variety of reserve estimation techniques from numerous assumptions and expectations about future events, many of which are highly uncertain, such as estimates of claims severity, frequency of claims, mortality, morbidity, discount rates, inflation, claims handling, case reserving policies and procedures, underwriting and pricing policies, changes in the legal and regulatory environment and the lag time between the occurrence of an insured event and the time of its ultimate settlement. Mortality is the relative incidence of death. Morbidity is the frequency and severity of illness, sickness and diseases contracted. Many of these uncertainties are not precisely quantifiable and require significant judgment on CNA’s part. As trends in underlying claims develop, particularly in so-called “long tail” or long duration coverages, CNA is sometimes required to add to its reserves. This is called unfavorable net prior year

 

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development and results in a charge to earnings in the amount of the added reserves, recorded in the period the change in estimate is made. These charges can be substantial.

CNA is also subject to the uncertain effects of emerging or potential claims and coverage issues that arise as industry practices and legal, judicial, social, economic and other environmental conditions change. These issues have had, and may continue to have, a negative effect on CNA’s business by either extending coverage beyond the original underwriting intent or by increasing the number or size of claims, resulting in further increases in CNA’s reserves. The effects of these and other unforeseen emerging claim and coverage issues are extremely hard to predict. Examples of emerging or potential claims and coverage issues include:

 

   

the effects of worldwide economic conditions, which have resulted in an increase in the number and size of certain claims including both directors and officers (“D&O”) and errors and omissions (“E&O”) insurance claims related to corporate failures, as well as other coverages;

 

   

class action litigation relating to claims handling and other practices; and

 

   

mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals, and various other chemical and radiation exposure claims.

In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews and changes its reserve estimates in a regular and ongoing process as experience develops and further claims are reported and settled. If estimated reserves are insufficient for any reason, the required increase in reserves would be recorded as a charge against earnings in the period in which reserves are determined to be insufficient. These charges could be substantial.

CNA’s key assumptions used to determine reserves for long term care products and payout annuity contracts could vary significantly from actual experience.

CNA’s reserves for long term care products and payout annuity contracts are based on certain key assumptions including morbidity, mortality, policy persistency (the percentage of policies remaining in force) and discount rates (which are impacted by expected investment yields). A prolonged period during which interest rates remain at levels lower than those anticipated in CNA’s reserving may result in shortfalls in investment income on assets supporting policy obligations, which may require changes to reserves. These assumptions, while based on historical data and industry experience and monitored consistently, are critical bases for reserve estimates and are inherently uncertain. If estimated reserves are insufficient for any reason, the required increase in reserves would be recorded as a charge against earnings in the period in which reserves are determined to be insufficient. These charges could be substantial.

Catastrophe losses are unpredictable and could result in material losses.

Catastrophe losses are an inevitable part of CNA’s business. Various events can cause catastrophe losses. These events can be natural or man-made, and may include hurricanes, windstorms, earthquakes, hail, severe winter weather, fires, and acts of terrorism. The frequency and severity of these catastrophe events are inherently unpredictable. In addition, longer-term natural catastrophe trends may be changing and new types of catastrophe losses may be developing due to climate change, a phenomenon that has been associated with extreme weather events linked to rising temperatures, and includes effects on global weather patterns, greenhouse gases, sea, land and air temperatures, sea levels, rain, hail and snow.

The extent of CNA’s losses from catastrophes is a function of the total amount of its insured exposures in the affected areas, the frequency and severity of the events themselves, the level of reinsurance assumed and ceded and reinsurance reinstatement premiums, if any. As in the case of catastrophe losses generally, it can take a long time for the ultimate cost to CNA to be finally determined, as a multitude of factors contribute to such costs, including evaluation of general liability and pollution exposures, additional living expenses, infrastructure disruption, business interruption and reinsurance collectibility. Reinsurance coverage for terrorism events is provided only in limited

 

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circumstances, especially in regard to “unconventional” terrorism acts, such as nuclear, biological, chemical or radiological attacks. As a result, catastrophe losses are particularly difficult to estimate.

As CNA’s claim experience develops on a specific catastrophe, CNA may be required to adjust its reserves, or take unfavorable net prior year development, to reflect revised estimates of the total cost of claims.

CNA has exposure related to A&EP claims, which could result in material losses.

CNA’s property and casualty insurance subsidiaries have exposures related to A&EP claims. CNA’s experience has been that establishing claim and claim adjustment expense reserves for casualty coverages relating to A&EP claims is subject to uncertainties that are greater than those presented by other claims. Additionally, traditional actuarial methods and techniques employed to estimate the ultimate cost of claims for more traditional property and casualty exposures are less precise in estimating claim and claim adjustment expense reserves for A&EP. As a result, estimating the ultimate cost of both reported and unreported A&EP claims is subject to a higher degree of variability.

On August 31, 2010, CNA completed a retroactive reinsurance transaction under which substantially all of its legacy A&EP liabilities were ceded to National Indemnity Company (“NICO”), a subsidiary of Berkshire Hathaway Inc., subject to an aggregate limit of $4.0 billion (“Loss Portfolio Transfer”). If the other parties to the Loss Portfolio Transfer do not fully perform their obligations, CNA’s liabilities for A&EP claims covered by the Loss Portfolio Transfer exceed the aggregate limit of $4.0 billion, or CNA determines it has exposures to A&EP claims not covered by the Loss Portfolio Transfer, CNA may need to increase its recorded net reserves which would result in a charge against CNA’s earnings. These charges could be substantial.

CNA’s premium writings and profitability are affected by the availability and cost of reinsurance.

CNA purchases reinsurance to help manage its exposure to risk. Under CNA’s ceded reinsurance arrangements, another insurer assumes a specified portion of CNA’s exposure in exchange for a specified portion of policy premiums. Market conditions determine the availability and cost of the reinsurance protection CNA purchases, which affects the level of its business and profitability, as well as the level and types of risk CNA retains. If CNA is unable to obtain sufficient reinsurance at a cost it deems acceptable, CNA may be unwilling to bear the increased risk and would reduce the level of its underwriting commitments.

CNA may not be able to collect amounts owed to it by reinsurers which could result in higher net incurred losses.

CNA has significant amounts recoverable from reinsurers which are reported as receivables on its balance sheets and are estimated in a manner consistent with claim and claim adjustment expense reserves or future policy benefits reserves. The ceding of insurance does not, however, discharge CNA’s primary liability for claims. As a result, CNA is subject to credit risk relating to its ability to recover amounts due from reinsurers. In the past, certain of CNA’s reinsurance carriers have experienced credit downgrades by rating agencies within the term of CNA’s contractual relationship. Such action increases the likelihood that CNA will not be able to recover amounts due. In addition, reinsurers could dispute amounts which CNA believes are due to it. If CNA is not able to collect the amounts due from reinsurers for any of the foregoing reasons, its net incurred losses will be higher.

CNA may not be able to collect amounts owed to it by policyholders who hold deductible policies which could result in higher net incurred losses.

A portion of CNA’s business is written under deductible policies. Under these policies, CNA is obligated to pay the related insurance claims and are reimbursed by the policyholder to the extent of the deductible, which may be significant. As a result CNA is exposed to credit risk to the policyholder. If CNA is not able to collect the amounts due from policyholders, its incurred losses will be higher.

 

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CNA has incurred and may continue to incur significant realized and unrealized investment losses and volatility in net investment income arising from volatility in the capital and credit markets.

CNA’s investment portfolio is exposed to various risks, such as interest rate, credit and currency risks, many of which are unpredictable. Investment returns are an important part of CNA’s overall profitability. General economic conditions, changes in financial markets such as fluctuations in interest rates, credit conditions and currency, commodity and stock prices, and many other factors beyond CNA’s control can adversely affect the value of its investments and the realization of investment income. Further, CNA invests a portion of its assets in equity securities and limited partnerships which are subject to greater market volatility than its fixed income investments. In addition, limited partnership investments generally present, higher illiquidity than fixed income investments. As a result of all of these factors, CNA may not realize an adequate return on its investments, may incur losses on sales of its investments, and may be required to write-down the value of its investments.

CNA’s valuation of investments and impairment of securities requires significant judgment which is inherently uncertain.

CNA exercises significant judgment in analyzing and validating fair values, which are primarily provided by third parties, for securities in its investment portfolio including those that are not regularly traded in active markets. CNA also exercises significant judgment in determining whether the impairment of particular investments is temporary or other-than-temporary. The valuation of residential and commercial mortgage and other asset backed securities can be particularly sensitive to fairly small changes in collateral performance. Due to the inherent uncertainties involved with these judgments, CNA may incur unrealized losses and conclude that other-than-temporary write-downs of its investments are required.

CNA is subject to capital adequacy requirements and, if it is unable to maintain or raise sufficient capital to meet these requirements, regulatory agencies may restrict or prohibit CNA from operating its business.

Insurance companies such as CNA are subject to capital adequacy standards set by regulators to help identify companies that merit further regulatory attention. These standards apply specified risk factors to various asset, premium and reserve components of statutory capital and surplus reported in CNA’s statutory basis of accounting financial statements. Current rules, including those promulgated by insurance regulators and specialized markets such as Lloyd’s, require companies to maintain statutory capital and surplus at a specified minimum level determined using the applicable regulatory capital adequacy formula. If CNA does not meet these minimum requirements, CNA may be restricted or prohibited from operating its business. If CNA is required to record a material charge against earnings in connection with a change in estimates or the occurrence of an event or if it incurs significant losses related to its investment portfolio, CNA may violate these minimum capital adequacy requirements unless it is able to raise sufficient additional capital.

While we have provided CNA with substantial amounts of capital in prior years, we may be restricted in our ability or may not be willing to provide additional capital support to CNA in the future. If CNA is in need of additional capital, CNA may be required to secure this funding from sources other than us. CNA may be limited in its ability to raise significant amounts of capital on favorable terms or at all.

CNA’s insurance subsidiaries, upon whom CNA depends for dividends in order to fund its working capital needs, are limited by insurance regulators in their ability to pay dividends.

CNA is a holding company and is dependent upon dividends, loans and other sources of cash from its subsidiaries in order to meet its obligations. Ordinary dividend payments or dividends that do not require prior approval by the insurance subsidiaries’ domiciliary insurance regulator are generally limited to amounts determined by formula which varies by jurisdiction. The formula for the majority of domestic states is the greater of 10% of the prior year statutory surplus or the prior year statutory net income, less the aggregate of all dividends paid during the twelve months prior to the date of payment. Some jurisdictions including certain domestic states, however, have an additional stipulation that dividends cannot exceed the prior year’s earned surplus. If CNA is restricted, by regulatory rule or otherwise, from paying or receiving inter-company dividends, CNA may not be able to fund its working capital needs and debt service requirements from available cash. As a result, CNA would need to look to other sources of capital which may be more expensive or may not be available at all.

 

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Rating agencies may downgrade their ratings of CNA and thereby adversely affect its ability to write insurance at competitive rates or at all.

Ratings are an important factor in establishing the competitive position of insurance companies. CNA’s insurance company subsidiaries, as well as CNA’s public debt, are rated by rating agencies, namely, A.M. Best Company (“A.M. Best”), Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s (“S&P”). Ratings reflect the rating agency’s opinions of an insurance company’s or insurance holding company’s financial strength, capital adequacy, operating performance, strategic position and ability to meet its obligations to policyholders and debt holders.

Due to the intense competitive environment in which CNA operates, the uncertainty in determining reserves and the potential for CNA to take material unfavorable net prior year development in the future, and possible changes in the methodology or criteria applied by the rating agencies, the rating agencies may take action to lower CNA’s ratings in the future. If CNA’s property and casualty insurance financial strength ratings are downgraded below current levels, CNA’s business and results of operations could be materially adversely affected. The severity of the impact on CNA’s business is dependent on the level of downgrade and, for certain products, which rating agency takes the rating action. Among the adverse effects in the event of such downgrades would be the inability to obtain a material volume of business from certain major insurance brokers, the inability to sell a material volume of CNA’s insurance products to certain markets, and the required collateralization of certain future payment obligations or reserves.

In addition, it is possible that a lowering of our corporate debt ratings by certain of the rating agencies could result in an adverse impact on CNA’s ratings, independent of any change in CNA’s circumstances. CNA has entered into several settlement agreements and assumed reinsurance contracts that require collateralization of future payment obligations and assumed reserves if its ratings or other specific criteria fall below certain thresholds. The ratings triggers are generally more than one level below CNA’s current ratings.

Risks Related to Us and Our Subsidiary, Diamond Offshore Drilling, Inc.

Diamond Offshore’s business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.

Diamond Offshore’s business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since Diamond Offshore’s customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for Diamond Offshore’s rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond Diamond Offshore’s control, including:

 

   

worldwide demand for oil and gas;

 

   

the level of economic activity in energy-consuming markets;

 

   

the worldwide economic environment or economic trends, such as recessions;

 

   

the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;

 

   

the level of production in non-OPEC countries;

 

   

the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;

 

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civil unrest;

 

   

the cost of exploring for, producing and delivering oil and gas;

 

   

the discovery rate of new oil and gas reserves;

 

   

the rate of decline of existing and new oil and gas reserves;

 

   

available pipeline and other oil and gas transportation and refining capacity;

 

   

the ability of oil and gas companies to raise capital;

 

   

weather conditions;

 

   

natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;

 

   

the policies of various governments regarding exploration and development of their oil and gas reserves;

 

   

development and exploitation of alternative fuels or energy sources;

 

   

competition for customers’ drilling budgets from land-based energy markets around the world;

 

   

domestic and foreign tax policy; and

 

   

advances in exploration and development technology.

Diamond Offshore’s business involves numerous operating hazards which could expose it to significant losses and significant damage claims. Diamond Offshore is not fully insured against all of these risks and its contractual indemnity provisions may not fully protect Diamond Offshore.

Diamond Offshore’s operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages.

Consistent with industry practice, Diamond Offshore’s contracts with its customers generally contain contractual rights to indemnity from its customer for, among other things, pollution originating from the well, while Diamond Offshore retains responsibility for pollution originating from the rig. However, Diamond Offshore’s contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by itself, its subcontractors and/or suppliers and Diamond Offshore’s customers may dispute, or be unable to meet, their contractual indemnification obligations.

Diamond Offshore maintains liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, Diamond Offshore’s insurance coverage may not adequately cover its losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, Diamond Offshore does not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Moreover, insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all.

 

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Diamond Offshore believes that the policy limit under its marine liability insurance is within the range that is customary for companies of its size in the offshore drilling industry and is appropriate for its business. However, if an accident or other event occurs that exceeds Diamond Offshore’s coverage limits or is not an insurable event under its insurance policies, or is not fully covered by contractual indemnity, it could have a material adverse effect on its results of operations, financial condition and cash flows. There can be no assurance that Diamond Offshore will continue to carry the insurance it currently maintains, that its insurance will cover all types of losses or that those parties with contractual obligations to indemnify Diamond Offshore will necessarily be financially able to indemnify Diamond Offshore against all of these risks. In addition, no assurance can be made that Diamond Offshore will be able to maintain adequate insurance in the future at rates it considers to be reasonable or that Diamond Offshore will be able to obtain insurance against some risks.

Diamond Offshore’s industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of Diamond Offshore’s competitors may have greater financial or other resources than it does. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.

Diamond Offshore’s industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. Diamond Offshore cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of Diamond Offshore’s drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

Significant new rig construction and upgrades of existing drilling rigs could also intensify price competition. Based on analyst reports, Diamond Offshore believes that there are approximately 67 floaters on order and scheduled for delivery between 2013 and 2016, with approximately 75% of these rigs scheduled for delivery in 2013 and 2014. The resulting increases in rig supply could be sufficient to depress rig utilization and intensify price competition from both existing competitors, as well as new entrants into the offshore drilling market. Not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. The majority of the floaters on order are dynamically positioned drilling rigs, which further increases competition with Diamond Offshore’s fleet in certain circumstances, depending on customer requirements. In Brazil, Petrobras, which accounted for approximately 33% of Diamond Offshore’s consolidated revenues in 2012 and, as of February 1, 2013, accounted for approximately $2.6 billion of contract drilling backlog through 2016 and to which nine of Diamond Offshore’s floaters are currently contracted, has announced plans to construct locally 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling rigs, if built, would increase rig supply and could intensify price competition in Brazil as well as other markets as they enter the market, would compete with, and could displace, Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect Diamond Offshore’s utilization rates, particularly in Brazil.

Diamond Offshore can provide no assurance that its current backlog of contract drilling revenue will be ultimately realized.

As of February 1, 2013, Diamond Offshore’s contract drilling backlog was approximately $8.6 billion for contracted future work extending, in some cases, until 2019. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, Diamond Offshore may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. Diamond Offshore can provide no assurance that it will be able to perform under these contracts due to events beyond its control or that Diamond Offshore will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, Diamond Offshore can provide no assurance that its customers will be able to or

 

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willing to fulfill their contractual commitments. Diamond Offshore’s inability to perform under its contractual obligations or to execute definitive agreements or its customers’ inability or unwillingness to fulfill their contractual commitments may have a material adverse effect on Diamond Offshore’s business.

Diamond Offshore relies heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on its financial results.

Diamond Offshore provides offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. In 2012, Diamond Offshore’s five largest customers in the aggregate accounted for 62% of its consolidated revenues. Diamond Offshore expects Petrobras and OGX, which accounted for approximately 33% and 12% of Diamond Offshore’s consolidated revenues in 2012, to continue to be significant customers in 2013. Diamond Offshore’s contract drilling backlog, as of February 1, 2013, includes $1.0 billion, or 36% and $187 million or 7% of its contracted backlog for 2013, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil. Petrobras has announced plans to construct locally, 29 new ultra-deepwater drilling units to be delivered beginning in 2015. These new drilling units, if built, would compete with, and could displace, Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect utilization rates, particularly in Brazil. While it is normal for Diamond Offshore’s customer base to change over time as work programs are completed, the loss of, or a significant reduction in the number of rigs contracted with, any major customer may have a material adverse effect on Diamond Offshore’s business.

The terms of Diamond Offshore’s drilling contracts may limit its ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market.

The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit Diamond Offshore’s profitability.

Contracts for Diamond Offshore’s drilling rigs are generally fixed dayrate contracts, and increases in Diamond Offshore’s operating costs could adversely affect the profitability on those contracts.

Diamond Offshore’s contracts for its drilling rigs provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by Diamond Offshore. Many of Diamond Offshore’s operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond Diamond Offshore’s control. The gross margin that Diamond Offshore realizes on these fixed dayrate contracts will fluctuate based on variations in Diamond Offshore’s operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, Diamond Offshore may be unable to fully recover increased or unforeseen costs from its customers.

Diamond Offshore’s drilling contracts may be terminated due to events beyond its control.

Diamond Offshore’s customers may terminate some of their term drilling contracts if the drilling rig is destroyed or lost or if Diamond Offshore has to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of Diamond Offshore’s drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. During periods of depressed market conditions, Diamond Offshore may be subject to an increased risk of its customers seeking to repudiate their contracts. Diamond Offshore’s

 

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customers’ ability to perform their obligations under drilling contracts may also be adversely affected by restricted credit markets and economic downturns. If Diamond Offshore’s customers cancel some of their contracts, and Diamond Offshore is unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or suspended for an extended period of time or if a number of contracts are renegotiated, it could materially and adversely affect Diamond Offshore’s financial condition, results of operations and cash flows.

Significant portions of Diamond Offshore’s operations are conducted outside the United States and involve additional risks not associated with domestic operations.

Diamond Offshore operates in various regions throughout the world which may expose it to political and other uncertainties, including risks of:

 

   

war and civil disturbances;

 

   

piracy or assaults on property or personnel;

 

   

kidnapping of personnel;

 

   

expropriation or nationalization of property or equipment;

 

   

renegotiation or nullification of existing contracts;

 

   

changing political conditions;

 

   

imposition of trade barriers or import-export quotas;

 

   

foreign and domestic monetary policies;

 

   

the inability to repatriate income or capital;

 

   

difficulties in collecting accounts receivable and longer collection periods;

 

   

fluctuations in currency exchange rates;

 

   

regulatory or financial requirements to comply with foreign bureaucratic actions;

 

   

travel limitations or operational problems caused by public health threats;

 

   

difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;

 

   

difficulties in obtaining visas or work permits for employees on a timely basis; and

 

   

changing taxation policies.

Diamond Offshore is subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing its international operations in addition to worldwide anti-bribery laws. In addition, international contract drilling operations are subject to various laws and regulations in countries in which Diamond Offshore operates, including laws and regulations relating to:

 

   

the equipping and operation of drilling rigs;

 

   

import - export quotas or other trade barriers;

 

   

repatriation of foreign earnings or capital;

 

   

oil and gas exploration and development;

 

   

taxation of offshore earnings and earnings of expatriate personnel; and

 

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use and compensation of local employees and suppliers by foreign contractors.

Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect Diamond Offshore’s ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments may materially and adversely affect Diamond Offshore’s ability to compete.

In addition, the shipment of goods, including the movement of a drilling rig across international borders, subjects Diamond Offshore to extensive trade laws and regulations. Diamond Offshore’s import activities are governed by unique customs laws and regulations that differ in each of the countries in which Diamond Offshore operates and often impose record keeping and reporting obligations. The laws and regulations concerning import/export activity and record keeping and reporting requirements are complex and change frequently. These laws and regulations may be enacted, amended enforced and/or interpreted in a manner that could materially and adversely impact Diamond Offshore’s operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which may be outside of Diamond Offshore’s control. Shipping delays or denials could cause unscheduled downtime for rigs. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to Diamond Offshore, among other things.

Diamond Offshore may enter into drilling contracts that exposes it to greater risks than it normally assumes.

From time to time, Diamond Offshore may enter into drilling contracts with national oil companies, government-controlled entities or others that expose it to greater risks than it normally assumes, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without cause or upon little or no notice. Upon termination, these contracts may not result in a payment to Diamond Offshore, or if a termination payment is required, it may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. For example, Diamond Offshore currently operates, and expects to continue to operate, its drilling rigs offshore Mexico for PEMEX – Exploración y Producción (“PEMEX”), the national oil company of Mexico. The terms of these contracts expose Diamond Offshore to greater environmental liability than it normally assumes, and provide that, among other things, each contract can be terminated by PEMEX on short notice, contractually or by statute, subject to certain conditions. While Diamond Offshore believes that the financial terms of these contracts and its operating safeguards in place mitigate these risks, it can provide no assurance that the increased risk exposure will not have a material negative impact on future operations or financial results.

Fluctuations in exchange rates and nonconvertibility of currencies could result in losses.

Due to Diamond Offshore’s international operations, Diamond Offshore may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where it does not effectively hedge an exposure to a foreign currency. Diamond Offshore may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. Diamond Offshore can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.

Diamond Offshore may be required to accrue additional tax liability on certain of its foreign earnings.

Certain of Diamond Offshore’s international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited (“DOIL”), a wholly owned Cayman Islands subsidiary of Diamond Offshore. It is Diamond Offshore’s intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. Diamond Offshore does not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future

 

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distribution be made from any unremitted earnings of this subsidiary, Diamond Offshore may be required to record additional U.S. income taxes.

Rig conversions, upgrades or new builds may be subject to delays and cost overruns.

From time to time, Diamond Offshore adds new capacity through conversions or upgrades to existing rigs or through new construction, such as its four, ultra-deepwater drillships under construction and its construction of the Ocean Apex and Ocean Onyx. Projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:

 

   

shortages of equipment, materials or skilled labor;

 

   

work stoppages;

 

   

unscheduled delays in the delivery of ordered materials and equipment;

 

   

unanticipated cost increases;

 

   

weather interferences or storm damage;

 

   

difficulties in obtaining necessary permits or in meeting permit conditions;

 

   

design and engineering problems;

 

   

availability of suppliers to recertify equipment for enhanced regulations;

 

   

customer acceptance delays;

 

   

shipyard failures or unavailability; and

 

   

failure or delay of third party service providers, civil unrest and labor disputes.

Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting in a loss of contract drilling backlog and revenue to Diamond Offshore. If a drilling contract is terminated under these circumstances, Diamond Offshore may not be able to secure a replacement contract with equally favorable terms.

Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM.

Because the amount of insurance coverage available to Diamond Offshore has been limited, and the cost for such coverage is substantial, Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts.

Risks Related to Us and Our Subsidiary, Boardwalk Pipeline Partners, LP

Boardwalk Pipeline may not be able to maintain or replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis.

Each year, a portion of Boardwalk Pipeline’s natural gas transportation contracts expire and need to be renewed or replaced. Boardwalk Pipeline may not be able to extend contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts. A key driver that influences the rates and terms of its transportation contracts is the current and anticipated basis spreads - generally meaning the difference in the price of natural gas at receipt and delivery points on its natural gas pipeline systems which influence how much

 

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customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by its pipeline systems. As new sources of natural gas have been identified and developed, changes in pricing dynamics between supply basins, pooling points and market areas have occurred. As a result of the increase in overall pipeline capacity and the new sources of supply, basis spreads on its pipeline systems have narrowed over the past several years, reducing the transportation rates Boardwalk Pipeline can negotiate with its customers on contracts due for renewal for its firm transportation services. The narrowing of basis differentials has also adversely affected the rates it is able to charge for its interruptible and short term firm transportation services. As a result, the rates Boardwalk Pipeline is able to obtain on renewals of expiring contracts are generally lower than those under the expiring contracts, which adversely impacts its revenues and distributable cash.

The development of large new gas supply basins in the U.S. and the overall increase in the supply of natural gas created by such development can significantly affect Boardwalk Pipeline’s business.

Growing supplies of natural gas are being produced in new production areas that are not connected to Boardwalk Pipeline’s system and are closer to large end-user market areas than the supply basins connected to its system that traditionally served these markets. For example, gas produced in the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio is being shipped to nearby northeast markets such as New York and Philadelphia which have traditionally been served by gas produced in Gulf Coast and mid-continent production areas which are connected to its pipelines. This has caused and may continue to cause gas produced in supply areas connected to its system to be diverted to other market areas which may adversely affect capacity utilization and transportation rates on its systems. In addition, as discussed above, growing supplies of natural gas from developing supply basins, especially shale plays, connected to Boardwalk Pipeline’s system have caused and may continue to cause basis spreads to narrow. All of these dynamics continue to impair Boardwalk Pipeline’s ability to renew or replace existing contracts or to sell interruptible and short term firm transportation services at attractive rates, which adversely impacts Boardwalk Pipeline’s revenues and distributable cash flows.

Changes in the price of natural gas and NGLs impacts supply of and demand for those commodities, which impacts Boardwalk Pipeline’s business.

Natural gas prices in the U.S. are currently lower than historical averages driven by the abundant and growing gas supply discussed above. The prices of natural gas and NGLs fluctuates in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:

 

   

worldwide economic conditions;

 

   

weather conditions, seasonal trends and hurricane disruptions;

 

   

the relationship between the available supplies and the demand for natural gas and NGLs;

 

   

new supply sources;

 

   

the availability of adequate transportation capacity;

 

   

storage inventory levels;

 

   

the price and availability of oil and other forms of energy;

 

   

the effect of energy conservation measures;

 

   

the nature and extent of, and changes in, governmental regulation, new regulations adopted by the EPA for example greenhouse gas legislation and taxation; and

 

   

the anticipated future prices of natural gas, oil and other commodities.

 

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It is difficult to predict future changes in natural gas and NGL prices. However, the economic environment that has existed over the last several years generally indicates a bias toward continued downward pressure on natural gas prices. Sustained low natural gas prices could negatively impact producers including those directly connected to Boardwalk Pipeline’s pipelines that have contracted for capacity with them.

Conversely, future increases in the price of natural gas could make alternative energy sources more competitive and reduce demand for natural gas. A reduced level of demand for natural gas could reduce the utilization of capacity on Boardwalk Pipeline’s systems, reduce the demand for its services and could result in the non-renewal of contracted capacity as contracts expire and affect its midstream businesses.

Boardwalk Pipeline may not have sufficient available cash, to continue making distributions to unitholders at the current distribution rate or at all.

The amount of cash Boardwalk Pipeline can distribute to its unitholders, including us, principally depends upon the amount of cash it generates from its operations and financing activities and the amount of cash it requires, or determines to use, for other purposes, all of which fluctuate from quarter to quarter based on a number of factors. Many of these factors are beyond the control of Boardwalk Pipeline. Some of the factors that influence the amount of cash Boardwalk Pipeline has available for distribution in any quarter include:

 

   

the level of capital expenditures it makes or anticipates making, including for expansion and growth projects;

 

   

the cost and form of payment for pending or anticipated acquisitions and growth or expansion projects and the commercial success of any such initiatives;

 

   

the amount of cash necessary to meet its current or anticipated debt service requirements and other liabilities;

 

   

fluctuations in working capital needs;

 

   

its ability to borrow funds and/or access capital markets to fund operations or capital expenditures, including acquisitions; restrictions contained in its debt agreements; and

 

   

fluctuations in cash generated by its operations, including as a result of the seasonality of its business, customer payment issues and general business conditions such as, among others, contract renewals, basis spreads, market rates, and fluctuations in PAL revenues.

Boardwalk Pipeline may determine to reduce or eliminate distributions at any time it determines that its cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects or other business needs. Any such reduction would reduce the amount of cash available to us.

Investments that Boardwalk Pipeline makes, whether through acquisitions or growth projects, that appear to be accretive may nevertheless reduce its distributable cash flows.

Boardwalk Pipeline plans to continue to grow and diversify its business by among other things, investing in assets through acquisitions and organic growth projects. Its ability to grow, diversify and increase distributable cash flows will depend, in part, on its ability to close and execute on accretive acquisitions and projects. Any such transaction involves potential risks that may include, among other things:

 

   

the diversion of management’s and employees’ attention from other business concerns;

 

   

inaccurate assumptions about volume, revenues and costs, including potential synergies;

 

   

a decrease in liquidity as a result of Boardwalk Pipeline using available cash or borrowing capacity to finance the acquisition or project;

 

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a significant increase in interest expense or financial leverage if Boardwalk Pipeline incurs additional debt to finance the acquisition or project;

 

   

inaccurate assumptions about the overall costs of equity or debt;

 

   

an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;

 

   

unforeseen difficulties operating in new product areas or new geographic areas; and

 

   

changes in regulatory requirements.

Additionally, acquisitions contain the following risks:

 

   

an inability to integrate successfully the businesses it acquires;

 

   

the assumption of unknown liabilities for which Boardwalk Pipeline is not indemnified, for which its indemnity is inadequate or for which its insurance policies may exclude from coverage;

 

   

limitations on rights to indemnity from the seller; and

 

   

customer or key employee losses of an acquired business.

Boardwalk Pipeline is exposed to credit risk relating to nonperformance by its customers.

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Boardwalk Pipeline’s exposure generally relates to receivables for services provided, future performance under firm agreements and volumes of gas or other products owed by customers for imbalances or product loaned by it to them under certain of its services. For Boardwalk Pipeline’s FERC-regulated business, Boardwalk Pipeline’s tariffs only allow it to require limited credit support in the event that its transportation customers are unable to pay for its services. If any of its significant customers have credit or financial problems which result in a delay or failure to pay for services provided by them or contracted for with them, or to repay the product they owe them, it could have a material adverse effect on Boardwalk Pipeline’s business. In addition, as contracts expire, the credit or financial failure of any of its customers could also result in the non-renewal of contracted capacity, which could have a material adverse effect on its business.

Boardwalk Pipeline depends on certain key customers for a significant portion of its revenues. The loss of any of these key customers could result in a decline in its revenues.

Boardwalk Pipeline relies on a limited number of customers for a significant portion of revenues. Its largest customer in terms of revenue, Devon Gas Services, LP, represented over 12% of its 2012 revenues. Boardwalk Pipeline’s top ten customers comprised approximately 47% of its revenues in 2012. Boardwalk Pipeline may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce its contracted transportation volumes and the rates it can charge for its services.

 

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Boardwalk Pipeline’s natural gas transportation and storage operations are subject to FERC’s rate-making policies which could limit its ability to recover the full cost of operating its pipelines, including earning a reasonable return.

Boardwalk Pipeline is subject to extensive regulations relating to the rates it can charge for its natural gas transportation and storage operations. For Boardwalk Pipeline’s cost-based services, FERC establishes both the maximum and minimum rates it can charge. The basic elements that FERC considers are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. Boardwalk Pipeline may not be able to recover all of its costs, including certain costs associated with pipeline integrity, through existing or future rates.

Customers or FERC can challenge the existing rates on any of Boardwalk Pipeline’s pipelines. Such a challenge against them could adversely affect its ability to charge rates that would cover future increases in its costs or even to continue to collect rates to maintain its current revenue levels that are designed to permit a reasonable opportunity to recover current costs and depreciation and earn a reasonable return.

If any of Boardwalk Pipeline’ pipelines under FERC jurisdiction were to file a rate case, or if they have to defend their rates in a proceeding commenced by a customer or FERC, Boardwalk Pipeline would be required, among other things, to establish that the inclusion of an income tax allowance in its cost of service is just and reasonable. Under current FERC policy, since it is a limited partnership and does not pay U.S. federal income taxes, this would require it to show that its unitholders (or their ultimate owners) are subject to federal income taxation. To support such a showing, Boardwalk Pipeline’s general partner may elect to require owners of its units to re-certify their status as being subject to U.S. federal income taxation on the income generated by Boardwalk Pipeline or may attempt to provide other evidence. Boardwalk Pipeline can provide no assurance that the evidence it might provide to FERC will be sufficient to establish that its unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income generated by Boardwalk Pipeline’s jurisdictional pipelines. If Boardwalk Pipeline is unable to make such a showing, FERC could disallow a substantial portion of the income tax allowance included in the determination of the maximum rates that may be charged by its pipelines, which could result in a reduction of such maximum rates from current levels.

Pipeline safety laws and regulations requiring the performance of integrity management programs or the use of certain safety technologies could subject Boardwalk Pipeline to increased capital and operating costs and require it to use more comprehensive and stringent safety controls.

Boardwalk Pipeline’s pipelines are subject to regulation by the DOT under the NGPSA with respect to natural gas and the HLPSA with respect to NGLs, both as amended. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGLs pipeline facilities. These amendments have resulted in the adoption of rules by the DOT, through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. These regulations have resulted in an overall increase in maintenance costs. Due to recent highly publicized incidents on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. Boardwalk Pipeline could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.

The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1 million to $2 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

 

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Boardwalk Pipeline needs to maintain authority from PHMSA to operate portions of its pipeline systems at higher than normal operating pressures.

Boardwalk Pipeline has entered into firm transportation contracts with shippers which utilize the design capacity of certain of its pipeline assets, assuming that Boardwalk Pipeline operates those pipeline assets at higher than normal operating pressures (up to 0.80 of the pipeline’s SMYS). Boardwalk Pipeline has authority from PHMSA to operate those pipeline assets at such higher pressures, however PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, Boardwalk Pipeline may not be able to transport all of its contracted quantities of natural gas on its pipeline assets and could incur significant additional costs to re-obtain such authority or to develop alternate ways to meet its contractual obligations.

Risks Related to Us and Our Subsidiary, HighMount Exploration & Production LLC

HighMount may not be able to replace reserves and sustain production at current levels. Replacing reserves is risky and uncertain and requires significant capital expenditures.

HighMount’s success depends largely upon its ability to find, develop or acquire additional reserves that are economically recoverable. Unless HighMount replaces the reserves produced through successful development, exploration or acquisition, its proved reserves will decline over time. HighMount may not be able to successfully find and produce reserves economically in the future or to acquire proved reserves at acceptable costs. HighMount makes a substantial amount of capital expenditures for the acquisition, exploration and development of reserves. HighMount’s net cash flows have been negatively impacted by reduced natural gas and NGL prices as well as increased drilling costs developing HighMount’s oil reserves. If HighMount’s cash flow from operations is not sufficient to fund its capital expenditure budget, there can be no assurance that financing will be available or available at favorable terms to meet those requirements.

Estimates of natural gas and oil reserves are uncertain and inherently imprecise.

Estimating the volume of proved natural gas and oil reserves is a complex process and is not an exact science because of numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, these estimates are inherently imprecise.

Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves most likely will vary from HighMount’s estimates. Any significant variance could materially affect the quantities and present value of HighMount’s reserves. In addition, HighMount may adjust estimates of proved reserves upward or downward to reflect production history, results of exploration and development drilling, prevailing commodity prices and prevailing development expenses.

The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate representation of their value.

If commodity prices remain depressed, HighMount may be required to take additional write-downs of the carrying values of its properties.

HighMount may be required, under full cost accounting rules, to write-down the carrying value of its natural gas and oil properties. A number of factors could result in a write-down, including continued low commodity prices, a substantial downward adjustment to estimated proved reserves, a substantial increase in estimated development costs, or deterioration in exploration results. It is difficult to predict future changes in gas prices. However, the abundance of natural gas supply discoveries over the last few years would generally indicate a bias toward downward pressure on prices. HighMount utilizes the full cost method of accounting for its exploration and development activities. Under full cost accounting, HighMount is required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of

 

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HighMount’s natural gas properties that is equal to the expected after tax present value (discounted at the required rate of 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges, calculated using the average first day of the month price for the preceding 12-month period.

If the net book value of HighMount’s exploration and production (“E&P”) properties (reduced by any related net deferred income tax liability) exceeds its ceiling limitation, HighMount will impair or “write-down” the book value of its E&P properties. HighMount recorded a ceiling test impairment charge in each quarter of 2012, totaling $433 million (after taxes) for the year ended December 31, 2012 as a result of declines in natural gas and NGL prices. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Depending on the magnitude of any future impairment, a ceiling test write-down could significantly reduce HighMount’s income, or produce a loss.

Natural gas, oil and other commodity prices are volatile.

The commodity price HighMount receives for its production heavily influences its revenue, profitability, access to capital and future rate of growth. If the current low price environment for natural gas continues, HighMount’s results of operations will be lower as well. HighMount is subject to risks due to frequent and possibly substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and HighMount expects this volatility to continue. The markets and prices for natural gas and oil depend upon factors beyond HighMount’s control. These factors include, among others, economic and market conditions, domestic production and import levels, storage levels, basis differentials, weather, government regulations and taxation. Lower commodity prices may reduce the amount of natural gas and oil that HighMount can produce economically.

HighMount engages in commodity price hedging activities.

The extent of HighMount’s commodity price risk is related to the effectiveness and scope of HighMount’s hedging activities. To the extent HighMount hedges its commodity price risk, HighMount will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor. Furthermore, because HighMount has entered into derivative transactions related to only a portion of its natural gas and oil production, HighMount will continue to have direct commodity price risk on the unhedged portion. HighMount’s actual future production may be significantly higher or lower than HighMount estimates at the time it enters into derivative transactions for that period.

As a result, HighMount’s hedging activities may not be as effective as HighMount intends in reducing the volatility of its cash flows, and in certain circumstances may actually increase the volatility of cash flows. In addition, even though HighMount’s management monitors its hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement or if the hedging arrangement is imperfect or ineffective.

Risks Related to Us and Our Subsidiaries Generally

In addition to the specific risks and uncertainties faced by our subsidiaries, as discussed above, we and all of our subsidiaries face risks and uncertainties related to, among other things, terrorism, hurricanes and other natural disasters, competition, government regulation, dependence on key executives and employees, litigation, dependence on information technology and compliance with environmental laws.

Acts of terrorism could harm us and our subsidiaries.

Future terrorist attacks and the continued threat of terrorism in this country or abroad, as well as possible retaliatory military and other action by the United States and its allies, could have a significant impact on the assets and businesses of certain of our subsidiaries. CNA issues coverages that are exposed to risk of loss from a terrorism act. Terrorist acts or the threat of terrorism, including increased political, economic and financial market instability and volatility in the price of oil and gas, could affect the market for Diamond Offshore’s drilling services, Boardwalk Pipeline’s transportation, gathering and storage services and HighMount’s exploration and production

 

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activities. In addition, future terrorist attacks could lead to reductions in business travel and tourism which could harm Loews Hotels. While our subsidiaries take steps that they believe are appropriate to secure their assets, there is no assurance that they can completely secure them against a terrorist attack or obtain adequate insurance coverage for terrorist acts at reasonable rates.

Our subsidiaries are subject to extensive federal, state and local governmental regulations.

The businesses operated by our subsidiaries are impacted by current and potential federal, state and local governmental regulations which impose or might impose a variety of restrictions and compliance obligations on those companies. Governmental regulations can also change materially in ways that could adversely affect those companies. Risks faced by our subsidiaries related to governmental regulation include the following:

CNA.  The insurance industry is subject to comprehensive and detailed regulation and supervision. Most insurance regulations are designed to protect the interests of CNA’s policyholders rather than its investors. Each jurisdiction in which CNA does business has established supervisory agencies that regulate its business. In addition, the Lloyd’s marketplace sets rules under which its members, including CNA’s Hardy syndicate operate. These rules and regulations include the following:

 

   

standards of solvency, including risk-based capital measurements;

 

   

restrictions on the nature, quality and concentration of investments;

 

   

restrictions on CNA’s ability to withdraw from unprofitable lines of insurance or unprofitable market areas;

 

   

the required use of certain methods of accounting and reporting;

 

   

the establishment of reserves for unearned premiums, losses and other purposes;

 

   

potential assessments for funds necessary to settle covered claims against impaired, insolvent or failed private or quasi-governmental insurers;

 

   

licensing of insurers and agents;

 

   

approval of policy forms;

 

   

limitations on the ability of CNA’s insurance subsidiaries to pay dividends to us; and

 

   

limitations on the ability to non-renew, cancel or change terms and conditions in policies.

Regulatory powers also extend to premium rate regulations which require that rates not be excessive, inadequate or unfairly discriminatory. CNA may also be required by the jurisdictions in which it does business to provide coverage to persons who would not otherwise be considered eligible. Each jurisdiction dictates the types of insurance and the level of coverage that must be provided to such involuntary risks. CNA’s share of these involuntary risks is mandatory and is generally a function of its respective share of the voluntary market by line of insurance in each jurisdiction.

Diamond Offshore.  The offshore drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. Diamond Offshore may be required to make significant capital expenditures for additional equipment to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to Diamond Offshore’s operating costs or result in a reduction in revenues associated with downtime required to install such equipment, or may otherwise significantly limit drilling activity.

 

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In the aftermath of the Macondo well blowout in April of 2010 and the subsequent investigation into the causes of the event, new rules have been implemented for oil and gas operations in the GOM and in many of the international locations in which Diamond Offshore operates, including new standards for well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system (“SEMS”). New regulations may continue to be announced, including rules regarding drilling systems and equipment, such as blowout preventer and well control systems and lifesaving systems as well as rules regarding employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. Such new regulations could require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase Diamond Offshore’s operating costs and cause downtime for its rigs if it is required to take any of them out of service between scheduled surveys or inspections, or if it is required to extend scheduled surveys or inspections, to meet any such new requirements. Diamond Offshore is not able to predict the likelihood, nature or extent of additional rulemaking, nor is it able to predict the future impact of these events on operations. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of Diamond Offshore’s operations, and enhanced permitting requirements as well as escalating costs borne by its customers could reduce exploration activity in the GOM and therefore demand for its services.

Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect Diamond Offshore’s operations by limiting drilling opportunities.

Boardwalk Pipeline.  Boardwalk Pipeline’s natural gas transportation and storage operations are subject to extensive regulation by FERC and the DOT among other federal and state authorities. In addition to FERC rules and regulations related to the rates Boardwalk Pipeline can charge for its services, federal regulations extend to pipeline safety, operating terms and conditions of service, the types of services Boardwalk Pipeline may offer, construction or abandonment of facilities, accounting and record keeping, and relationships and transactions with affiliated companies. These regulations can adversely impact Boardwalk Pipeline’s ability to compete for business, construct new facilities, including by increasing the lead times to develop projects, offer new services, or recover the full cost of operating its pipelines.

HighMount.  All of HighMount’s operations are conducted onshore in the United States. The U.S. oil and gas industry, and HighMount’s operations, are subject to regulation at the federal, state and local level. Such regulation includes requirements with respect to, among other things: permits to drill and to conduct other operations; provision of financial assurances (such as bonds) covering drilling and well operations; the location of wells; the method of drilling and completing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; the marketing, transportation and reporting of production; the valuation and payment of royalties; the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area); the unitization or pooling of natural gas and oil properties; maximum rates of production from natural gas and oil wells; venting or flaring of natural gas; and the ratability of production and the operation of gathering systems and related assets. Changes in these regulations, which HighMount cannot predict, could be harmful to HighMount’s business and results of operations.

Hydraulic fracturing is a technique commonly used by oil and gas exploration companies, including HighMount, to stimulate the production of oil and natural gas by injecting fluids and sand into underground wells at high pressures, causing fractures or fissures in the geological formation which allow oil and gas to flow more freely. In recent years, concerns have been raised that the fracturing process and disposal of drilling fluids may contaminate underground sources of drinking water. The conference committee report for The Department of the Interior, Environment, and Related Agencies Appropriations Act for Fiscal Year 2010 requested the EPA to conduct a study of hydraulic fracturing, particularly the relationship between hydraulic fracturing and drinking water. In December of 2012 the EPA issued a progress report of the projects the EPA is conducting as part of the study. A final draft report is expected to be released for public comment and peer review in 2014. Several bills were introduced in the 111th and 112th Congresses seeking federal regulation of hydraulic fracturing, which has historically been regulated at the state level, though none of the proposed legislation was passed into law. Similar bills may be introduced in the

 

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current Congress and a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. If hydraulic fracturing is banned or significantly restricted by federal regulation or otherwise, it could impair HighMount’s ability to economically drill new wells, which would reduce its production, revenues and profitability.

HighMount owns and operates gas gathering lines and related facilities which are regulated by the DOT and state agencies with respect to safety and operating conditions. PHMSA has established minimum federal safety standards for certain gas gathering lines. PHMSA has indicated that changes to the current regulatory framework are needed to address gas exploration and production activities. If implemented, the new changes could impact HighMount’s ability to transport some of its natural gas or cause HighMount to incur additional costs.

Our subsidiaries face significant risks related to compliance with environmental laws.

Our subsidiaries have extensive obligations and financial exposure related to compliance with federal, state and local environmental laws, many of which have become increasingly stringent in recent years and may in some cases impose strict liability, which could be substantial, rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. For example, Diamond Offshore could be liable for damages and costs incurred in connection with oil spills related to its operations, including for conduct of or conditions caused by others. HighMount is subject to extensive environmental regulation in the conduct of its business, particularly related to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. Boardwalk Pipeline is also subject to laws and regulations, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which it disposes of waste, requiring remedial action to remove or mitigate contamination and requiring capital expenditures to comply with pollution control requirements.

We are subject to physical and financial risks associated with climate change.

As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our subsidiaries and their suppliers and customers. We and our subsidiaries may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and related services provided by our energy subsidiaries. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas. In addition, changing global weather patterns have been associated with extreme weather events and could change longer-term natural catastrophe trends, including increasing the frequency and severity of hurricanes and other natural disasters which could increase future catastrophe losses at CNA and damage to property, disruption of business and higher operating costs at Diamond Offshore, Boardwalk Pipeline, HighMount and Loews Hotels.

There is currently no federal regulation that limits GHG emissions in the U.S. However, several bills were introduced in Congress in recent years that would regulate U.S. GHG emissions under a cap and trade system. Although these bills were not passed into law, some regulation of that type may be enacted in the U.S. in the near future. In addition, in 2009 the EPA adopted regulations under the Clean Air Act requiring the monitoring and reporting of annual GHG emissions by operators of facilities that emit more than 25,000 metric tons of GHG per year, which includes Boardwalk Pipeline and HighMount. Numerous states and several regional multi-state climate initiatives have announced or adopted plans to regulate GHG emissions, though the state programs vary widely. The establishment of a GHG reporting system and registry may be a first step toward broader regulation of GHG emissions. Compliance with future laws and regulations could impose significant costs on affected companies or adversely affect the demand for and the cost to produce and transport hydrocarbon-based fuel, which would adversely affect the businesses of our energy subsidiaries.

 

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Any significant interruption in the operation of critical computer systems could materially disrupt operations.

We and our subsidiaries have become more reliant on technology to help increase efficiency in our businesses. We are dependent upon operational and financial computer systems to process the data necessary to conduct almost all aspects of our businesses. Any failure of our or our subsidiaries’ computer systems, or those of our or their customers, vendors or others with whom we and they do business, could materially disrupt business operations. Computer and other business facilities and systems could become unavailable or impaired from a variety of causes, including among others, storms and other natural disasters, terrorist attacks, utility outages or complications encountered as existing systems are replaced or upgraded. In addition, it has been reported that unknown entities or groups have mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Any cyber attacks that affect our or our subsidiaries’ facilities could have a material adverse effect on our and their business or reputation.

Loss of key vendor relationships or failure of a vendor to protect personal information could result in a materially adverse effect on our operations.

We and our subsidiaries rely on services and products provided by many vendors in the United States and abroad. These include, for example, vendors of computer hardware, software and services, as well as other critical materials and services. If one or more key vendors becomes unable to continue to provide products or services, or fails to protect our proprietary information, including in some cases personal information of employees, customers or hotel guests, we and our subsidiaries may experience a material adverse effect on our or their business or reputation.

We could incur impairment charges related to the carrying value of the long-lived assets and goodwill of our subsidiaries.

Our subsidiaries regularly evaluate their long-lived assets and goodwill for impairment whenever events or changes in circumstances indicate the carrying value of these assets may not be recoverable. Most notably, we could incur impairment charges related to the carrying value of offshore drilling equipment at Diamond Offshore, natural gas and oil properties at HighMount, pipeline equipment at Boardwalk Pipeline and hotel properties owned by Loews Hotels.

We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit’s fair value as of the testing date. We calculate the fair value of our reporting units (each of our principal operating subsidiaries) based on estimates of future discounted cash flows, which reflect management’s judgments and assumptions regarding the appropriate risk-adjusted discount rate, future industry conditions and operations and other factors. Asset impairment evaluations are, by nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets which could impact the need to record an impairment charge and the amount of any charge taken.

We are a holding company and derive substantially all of our income and cash flow from our subsidiaries.

We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to holders of our common stock. Our subsidiaries are separate and independent legal entities and have no obligation, contingent or otherwise, to make funds available to us, whether in the form of loans, dividends or otherwise. The ability of our subsidiaries to pay dividends to us is also subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies, and their compliance with covenants in their respective loan agreements. Claims of creditors of our subsidiaries will generally have priority as to the assets of such subsidiaries over our claims and our creditors and shareholders.

 

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We could have liability in the future for tobacco-related lawsuits.

As a result of our ownership of Lorillard, Inc. (“Lorillard”) prior to the separation of Lorillard from us in 2008 (the “Separation”), from time to time we have been named as a defendant in tobacco-related lawsuits and could be named as a defendant in additional tobacco-related suits, notwithstanding the completion of the Separation. In the Separation Agreement entered into between us and Lorillard and its subsidiaries in connection with the Separation, Lorillard and each of its subsidiaries has agreed to indemnify us for liabilities related to Lorillard’s tobacco business, including liabilities that we may incur for current and future tobacco-related litigation against us. An adverse decision in a tobacco-related lawsuit against us could, if the indemnification is deemed for any reason to be unenforceable or any amounts owed to us thereunder are not collectible, in whole or in part, have a material adverse effect on our financial condition, results of operations and equity. We do not expect that the Separation will alter the legal exposure of either entity with respect to tobacco-related claims. We do not believe that we have any liability for tobacco-related claims, and we have never been held liable for any such claims.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our corporate headquarters is located in approximately 136,000 square feet of leased office space in New York City. Information relating to our subsidiaries’ properties is contained under Item 1.

Item 3. Legal Proceedings.

None.

Item 4. Mine Safety Disclosures.

None.

 

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PART II

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

Price Range of Common Stock

Our common stock is listed on the New York Stock Exchange under the symbol “L.” The following table sets forth the reported high and low sales prices in each calendar quarter:

 

     2012    2011  
  

 

 

 
     High                Low           High           Low  

 

 

First Quarter

         $    40.16            $    37.02            $    45.31            $    39.06       

Second Quarter

     41.80            38.14            44.46            39.99       

Third Quarter

     42.86            39.04            42.64            33.79       

Fourth Quarter

     43.36            39.57            41.66            32.90       

The following graph compares annual total return of our Common Stock, the Standard & Poor’s 500 Composite Stock Index (“S&P 500 Index”) and our Peer Group (“Loews Peer Group”) for the five years ended December 31, 2012. The graph assumes that the value of the investment in our Common Stock, the S&P 500 Index and the Loews Peer Group was $100 on December 31, 2007 and that all dividends were reinvested.

 

LOGO

 

     2007     2008      2009      2010      2011      2012  

Loews Common Stock

   100.00     56.48     73.34     79.06     76.98        83.84

S&P 500 Index

   100.00     63.00     79.67     91.68     93.61     108.59

Loews Peer Group (a)

   100.00     60.93     78.15     86.97     91.66     104.06

 

(a)

The Loews Peer Group consists of the following companies that are industry competitors of our principal operating subsidiaries: Ace Limited, W.R. Berkley Corporation, Cabot Oil & Gas Corporation, The Chubb Corporation, Energy Transfer Partners L.P., Ensco plc, The Hartford Financial Services Group, Inc., Kinder Morgan Energy Partners, L.P., Noble Corporation, Range Resources Corporation, Spectra Energy Corp, Transocean Ltd. and The Travelers Companies, Inc.

 

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Dividend Information

We have paid quarterly cash dividends on Loews common stock in each year since 1967. Regular dividends of $0.0625 per share of Loews common stock were paid in each calendar quarter of 2012 and 2011.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides certain information as of December 31, 2012 with respect to our equity compensation plans under which our equity securities are authorized for issuance.

 

Plan category   Number of
securities to be
issued upon exercise
of outstanding
options, warrants
and rights
    Weighted average
exercise price of
outstanding options,
warrants and rights
    Number of
securities remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in the first column)
 

 

 

Equity compensation plans approved by security holders (a)

    6,535,150                $     36.96              7,129,900         

Equity compensation plans not approved by security
holders (b)

    N/A                  N/A              N/A             

 

(a)

Reflects stock options and stock appreciation rights awarded under the Loews Corporation 2000 Stock Option Plan.

(b)

We do not have equity compensation plans that have not been approved by our shareholders.

Approximate Number of Equity Security Holders

We have approximately 1,170 holders of record of our common stock.

Common Stock Repurchases

We repurchased our common stock in 2012 as follows:

 

Period   Total number of
shares purchased
    Average price
paid per share

 

January 1, 2012 – March 31, 2012

    2,500            $38.42

April 1, 2012 – June 30, 2012

    1,302,700              38.99

July 1, 2012 – September 30, 2012

    2,187,630              40.11

October 1, 2012 – December 31, 2012

    2,060,000              40.60

 

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Item 6. Selected Financial Data.

The following table presents selected financial data. The table should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data of this Form 10-K.

 

Year Ended December 31    2012     2011     2010     2009     2008  

 

 
(In millions, except per share data)                               

Results of Operations:

          

Revenues

   $   14,552      $   14,129      $   14,615      $   14,117      $   13,247      

Income before income tax

   $ 1,399      $ 2,226      $ 2,902      $ 1,728      $ 594      

Income from continuing operations

   $ 1,110      $ 1,694      $ 2,008      $ 1,384      $ 585      

Discontinued operations, net

         (20     (2     4,713      

 

 

Net income

     1,110        1,694        1,988        1,382        5,298      

Amounts attributable to noncontrolling interests

     (542     (632     (699     (819     (763)     

 

 

Net income attributable to Loews Corporation

   $ 568      $ 1,062      $ 1,289      $ 563      $ 4,535      

 

 

Income (loss) attributable to:

          

Loews common stock:

          

Income (loss) from continuing operations

   $ 568      $ 1,062      $ 1,308      $ 565      $ (177)     

Discontinued operations, net

         (19     (2     4,501      

 

 

Loews common stock

     568        1,062        1,289        563        4,324      

Former Carolina Group stock:

          

Discontinued operations, net

             211      

 

 

Net income

   $ 568      $ 1,062      $ 1,289      $ 563      $ 4,535      

 

 

Diluted Net Income (Loss) Per Share:

          

Loews common stock:

          

Income (loss) from continuing operations

   $ 1.43      $ 2.62      $ 3.11      $ 1.31      $ (0.37)     

Discontinued operations, net

         (0.04     (0.01     9.43      

 

 

Net income

   $ 1.43      $ 2.62      $ 3.07      $ 1.30      $ 9.06      

 

 

Former Carolina Group stock:

          

Discontinued operations, net

   $ -            $ -           $ -           $ -           $ 1.95      

 

 

Financial Position:

          

Investments

   $   53,048      $ 49,028      $ 48,907      $ 46,034      $ 38,450      

Total assets

     80,021        75,268        76,198        73,990        69,791      

Debt

     9,210        9,001        9,477        9,485        8,258      

Shareholders’ equity

     19,459        18,772        18,386        16,833        13,068      

Cash dividends per share:

          

Loews common stock

     0.25        0.25        0.25        0.25        0.25      

Former Carolina Group stock

     -             -             -             -             0.91      

Book value per share of Loews common stock

     49.67        47.33        44.35        39.60        30.04      

Shares outstanding of Loews common stock

     391.81        396.59        414.55        425.07        435.09      

 

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

Management’s discussion and analysis of financial condition and results of operations is comprised of the following sections:

 

         Page    
No.

Overview

  

Consolidated Financial Results

   48

Parent Company Structure

   48

Critical Accounting Estimates

   49

Results of Operations by Business Segment

   52

CNA Financial

   52

Diamond Offshore

   65

Boardwalk Pipeline

   72

HighMount

   74

Loews Hotels

   77

Corporate and Other

   79

Liquidity and Capital Resources

   80

CNA Financial

   80

Diamond Offshore

   81

Boardwalk Pipeline

   82

HighMount

   83

Loews Hotels

   84

Corporate and Other

   84

Contractual Obligations

   85

Investments

   86

Accounting Standards Update

   90

Forward-Looking Statements

   91

 

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OVERVIEW

We are a holding company. Our subsidiaries are engaged in the following lines of business:

 

   

commercial property and casualty insurance (CNA Financial Corporation (“CNA”), a 90% owned subsidiary);

 

   

operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc. (“Diamond Offshore”), a 50.4% owned subsidiary);

 

   

transportation and storage of natural gas and natural gas liquids and gathering and processing of natural gas (Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”), a 55% owned subsidiary);

 

   

exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC (“HighMount”), a wholly owned subsidiary); and

 

   

operation of hotels (Loews Hotels Holding Corporation (“Loews Hotels”), a wholly owned subsidiary).

Unless the context otherwise requires, references in this Report to “Loews Corporation,” “the Company,” “Parent Company,” “we,” “our,” “us” or like terms refer to the business of Loews Corporation excluding its subsidiaries.

The following discussion should be read in conjunction with Item 1A, Risk Factors, and Item 8, Financial Statements and Supplementary Data of this Form 10-K.

Consolidated Financial Results

Consolidated net income for the year ended December 31, 2012 was $568 million, or $1.43 per share, compared to $1.1 billion, or $2.62 per share, in 2011. Net income in 2012 includes catastrophe losses of $243 million (after tax and noncontrolling interests) at CNA primarily related to Storm Sandy and after tax ceiling test impairment charges of $433 million at HighMount related to the carrying value of its natural gas and oil properties reflecting declines in natural gas and NGL prices. Lower results at Diamond Offshore also contributed to the reduction in net income, partially offset by higher earnings at Boardwalk Pipeline and higher parent company investment income as a result of improved performance of equity investments.

CNA’s earnings declined due to higher catastrophe losses related to Storm Sandy and a lower level of favorable net prior year development in 2012 than in 2011, partially offset by increased investment income. Increased investment income reflects improved performance of limited partnership investments.

Diamond Offshore earnings decreased as a result of lower rig utilization and a decrease in average dayrate partially offset by lower interest expense.

Boardwalk Pipeline’s earnings increased primarily due to the contributions from recent acquisitions, lower general and administrative expenses as well as lower impairment charges in 2012.

Book value per share increased to $49.67 at December 31, 2012 from $47.33 at December 31, 2011.

Parent Company Structure

We are a holding company and derive substantially all of our cash flow from our subsidiaries. We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to our shareholders. The ability of our subsidiaries to pay dividends is subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies (see Note 13 of the Notes to Consolidated Financial Statements included under Item 8) and compliance with covenants in their respective loan agreements. Claims of creditors of

 

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our subsidiaries will generally have priority as to the assets of such subsidiaries over our claims and those of our creditors and shareholders.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires us to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the related notes. Actual results could differ from those estimates.

The Consolidated Financial Statements and accompanying notes have been prepared in accordance with GAAP, applied on a consistent basis. We continually evaluate the accounting policies and estimates used to prepare the Consolidated Financial Statements. In general, our estimates are based on historical experience, evaluation of current trends, information from third party professionals and various other assumptions that we believe are reasonable under the known facts and circumstances.

We consider the accounting policies discussed below to be critical to an understanding of our Consolidated Financial Statements as their application places the most significant demands on our judgment. Due to the inherent uncertainties involved with these types of judgments, actual results could differ significantly from estimates, which may have a material adverse impact on our results of operations or equity.

Insurance Reserves

Insurance reserves are established for both short and long-duration insurance contracts. Short-duration contracts are primarily related to property and casualty insurance policies where the reserving process is based on actuarial estimates of the amount of loss, including amounts for known and unknown claims. Long-duration contracts include long term care products and payout annuity contracts and are estimated using actuarial estimates about mortality, morbidity and persistency as well as assumptions about expected investment returns. The reserve for unearned premiums on property and casualty contracts represents the portion of premiums written related to the unexpired terms of coverage. The reserving process is discussed in further detail in the Reserves – Estimates and Uncertainties section below.

Reinsurance and Other Receivables

An exposure exists with respect to the collectibility of ceded property and casualty and life reinsurance to the extent that any reinsurer is unable to meet its obligations or disputes the liabilities CNA has ceded under reinsurance agreements. An allowance for doubtful accounts on reinsurance receivables is recorded on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, CNA’s past experience and current economic conditions. Further information on CNA’s reinsurance receivables is included in Note 16 of the Notes to Consolidated Financial Statements included under Item 8.

Additionally, an exposure exists with respect to the collectibility of amounts due from customers on other receivables. An allowance for doubtful accounts is recorded on the basis of periodic evaluations of balances due currently or in the future, management’s experience and current economic conditions.

If actual experience differs from the estimates made by management in determining the allowances for doubtful accounts on reinsurance and other receivables, net receivables as reflected on our Consolidated Balance Sheets may not be collected. Therefore, our results of operations and/or equity could be materially adversely impacted.

Litigation

We and our subsidiaries are involved in various legal proceedings that have arisen during the ordinary course of business. We evaluate the facts and circumstances of each situation, and when management determines it necessary, a liability is estimated and recorded. Please read Note 18 of the Notes to Consolidated Financial Statements included under Item 8.

 

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Valuation of Investments and Impairment of Securities

We classify fixed maturity securities and equity securities as either available-for-sale or trading which are both carried at fair value. Fair value represents the price that would be received in a sale of an asset in an orderly transaction between market participants on the measurement date, the determination of which requires us to make a significant number of assumptions and judgments. Securities with the greatest level of subjectivity around valuation are those that rely on inputs that are significant to the estimated fair value and that are not observable in the market or cannot be derived principally from or corroborated by observable market data. These unobservable inputs are based on assumptions consistent with what we believe other market participants would use to price such securities. Further information on fair value measurements is included in Note 4 of the Notes to Consolidated Financial Statements included under Item 8.

CNA’s investment portfolio is subject to market declines below amortized cost that may be other-than-temporary and therefore result in the recognition of impairment losses in earnings. Factors considered in the determination of whether or not a decline is other-than-temporary include a current intention or need to sell the security or an indication that a credit loss exists. Significant judgment exists regarding the evaluation of the financial condition and expected near-term and long term prospects of the issuer, the relevant industry conditions and trends, and whether CNA expects to receive cash flows sufficient to recover the entire amortized cost basis of the security. CNA has an Impairment Committee which reviews the investment portfolio on at least a quarterly basis, with ongoing analysis as new information becomes available. Further information on CNA’s process for evaluating impairments is included in Note 3 of the Notes to Consolidated Financial Statements included under Item 8.

Long Term Care Products and Payout Annuity Contracts

Future policy benefit reserves for CNA’s long term care products and payout annuity contracts are based on certain assumptions including morbidity, mortality, policy persistency and discount rates, which are impacted by expected investment yields. The adequacy of the reserves are contingent on actual experience related to these key assumptions, which were generally established at time of issue. If actual experience differs from these assumptions, the reserves may not be adequate, requiring CNA to add to reserves. Therefore, our results of operations and/or equity could be adversely impacted. The reserving process is discussed in further detail in the Reserves – Estimates and Uncertainties section below.

Pension and Postretirement Benefit Obligations

We make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations under our benefit plans. The assumptions that have the most impact on pension costs are the discount rate and the expected long term rate of return on plan assets. These assumptions are evaluated relative to current market factors such as inflation, interest rates and fiscal and monetary policies. Changes in these assumptions can have a material impact on pension obligations and pension expense.

In determining the discount rate assumption, we utilized current market information and liability information, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate are comprised of high quality corporate bonds that are rated AA by an accepted rating agency.

Further information on our pension and postretirement benefit obligations is included in Note 15 of the Notes to Consolidated Financial Statements included under Item 8.

Valuation of HighMount’s Proved Reserves

HighMount follows the full cost method of accounting for natural gas and oil exploration and production activities. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. The depletable base of costs includes estimated future costs to be incurred in developing proved natural gas and oil reserves, as well as

 

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capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depletable base are subject to a ceiling test. The test limits capitalized amounts to a ceiling, the present value of estimated future net revenues to be derived from the production of proved natural gas and oil reserves, using calculated average prices adjusted for any cash flow hedges in place. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a write-down of the assets must be recognized in that period. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. For the year ended December 31, 2012, HighMount recognized non-cash impairment charges of $680 million ($433 million after tax) related to the carrying value of natural gas and oil properties, as discussed further in Note 7 of the Notes to Consolidated Financial Statements included under Item 8. In addition, gains or losses on the sale or other disposition of natural gas and oil properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

HighMount’s estimate of proved reserves requires a high degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. HighMount’s estimated proved reserves are based upon studies for each of its properties prepared by HighMount staff engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Determination of proved reserves is based on, among other things, (i) a pricing mechanism for oil and gas reserves which uses an average 12-month price; (ii) a limitation on the classification of reserves as proved undeveloped to locations scheduled to be drilled within five years; and (iii) a 10% discount factor used in calculating discounted future net cash flows.

The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of HighMount’s estimates or assumptions in the future and revisions to the value of HighMount’s proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. Given the volatility of natural gas and oil prices, it is possible that HighMount’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near term.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company uses a probability-weighted cash flow analysis to test property and equipment for impairment based on relevant market data. If an asset is determined to be impaired, a loss is recognized to reduce the carrying amount to the fair value of the asset. Management’s cash flow assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from the reported amounts.

Goodwill

Goodwill is required to be evaluated on an annual basis and whenever, in management’s judgment, there is a significant change in circumstances that would be considered a triggering event. Management must apply judgment in assessing qualitatively whether events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Factors such as a reporting unit’s planned future operating results, long term growth outlook and industry and market conditions are considered. Judgment is also applied in determining the estimated fair value of reporting units’ assets and liabilities for purposes of performing quantitative goodwill impairment tests. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples.

Income Taxes

Deferred income taxes are recognized for temporary differences between the financial statement and tax return bases of assets and liabilities. Any resulting future tax benefits are recognized to the extent that realization of such benefits is more likely than not, and a valuation allowance is established for any portion of a deferred tax asset that management believes may not be realized. The assessment of the need for a valuation allowance requires

 

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management to make estimates and assumptions about future earnings, reversal of existing temporary differences and available tax planning strategies. If actual experience differs from these estimates and assumptions, the recorded deferred tax asset may not be fully realized resulting in an increase to income tax expense in our results of operations. In addition, the ability to record deferred tax assets in the future could be limited resulting in a higher effective tax rate in that future period.

The Company has not established deferred tax liabilities for certain of its foreign earnings as it intends to indefinitely reinvest those earnings to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material impact on our financial results.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

Unless the context otherwise requires, references to net operating income (loss), net realized investment results and net income (loss) reflect amounts attributable to Loews Corporation Shareholders.

CNA Financial

Reserves – Estimates and Uncertainties

Property and Casualty Claim and Claim Adjustment Expense Reserves

CNA maintains loss reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for claims that have been reported but not yet settled (case reserves) and claims that have been incurred but not reported (“IBNR”). Claim and claim adjustment expense reserves are reflected as liabilities and are included on the Consolidated Balance Sheets under the heading “Insurance Reserves.” Adjustments to prior year reserve estimates, if necessary, are reflected in results of operations in the period that the need for such adjustments is determined. The carried case and IBNR reserves as of each balance sheet date are provided in the discussion that follows and in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

The level of reserves CNA maintains represents its best estimate, as of a particular point in time, of what the ultimate settlement and administration of claims will cost based on CNA’s assessment of facts and circumstances known at that time. Reserves are not an exact calculation of liability but instead are complex estimates that CNA derives, generally utilizing a variety of actuarial reserve estimation techniques, from numerous assumptions and expectations about future events, both internal and external, many of which are highly uncertain.

CNA is subject to the uncertain effects of emerging or potential claims and coverage issues that arise as industry practices and legal, judicial, social, economic and other environmental conditions change. These issues have had, and may continue to have, a negative effect on CNA’s business by either extending coverage beyond the original underwriting intent or by increasing the number or size of claims. Examples of emerging or potential claims and coverage issues include:

 

   

the effects of worldwide economic conditions, which have resulted in an increase in the number and size of certain claims including both directors and officers (“D&O”) and errors and omissions (“E&O”) insurance claims related to corporate failures, as well as other coverages;

 

   

class action litigation relating to claims handling and other practices; and

 

   

mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals and various other chemical and radiation exposure claims.

The impact of these and other unforeseen emerging or potential claims and coverage issues is difficult to predict and could materially adversely affect the adequacy of CNA’s claim and claim adjustment expense reserves and could lead to future reserve additions.

 

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CNA’s property and casualty insurance subsidiaries also have actual and potential exposures related to asbestos and environmental pollution (“A&EP”) claims. CNA’s experience has been that establishing reserves for casualty coverages relating to A&EP claims and the related claim adjustment expenses are subject to uncertainties that are greater than those presented by other claims. Additionally, traditional actuarial methods and techniques employed to estimate the ultimate cost of claims for more traditional property and casualty exposures are less precise in estimating claim and claim adjustment reserves for A&EP. As a result, estimating the ultimate cost of both reported and unreported A&EP claims is subject to a higher degree of variability.

To mitigate the risks posed by CNA’s exposure to A&EP claims and claim adjustment expenses, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August 31, 2010, CNA completed a transaction with NICO, a subsidiary of Berkshire Hathaway Inc., under which substantially all of CNA’s legacy A&EP liabilities were ceded to NICO effective January 1, 2010 (“Loss Portfolio Transfer”).

The Loss Portfolio Transfer is considered a retroactive reinsurance contract. In the event that the cumulative claim and allocated claim adjustment expenses ceded under the Loss Portfolio Transfer exceed the consideration paid, the resulting gain from such excess would be deferred. A cumulative amortization adjustment would be recognized in earnings in the period such excess arises so that the resulting deferred gain would reflect the balance that would have existed if the revised estimate was available at the inception date of the Loss Portfolio Transfer. This accounting generally results in a reserve charge because of the timing difference between the recognition of the gross adverse reserve development and the related ceded reinsurance benefit. However, there is no economic impact as long as the additional losses are within the limit under the contract. Any future adverse prior year development in excess of approximately $230 million would put the Loss Portfolio Transfer into an overall gain position under retroactive reinsurance accounting.

Establishing Reserve Estimates

In developing claim and claim adjustment expense (“loss” or “losses”) reserve estimates, CNA’s actuaries perform detailed reserve analyses that are staggered throughout the year. The data is organized at a “product” level. A product can be a line of business covering a subset of insureds such as commercial automobile liability for small or middle market customers, it can encompass several lines of business provided to a specific set of customers such as dentists, or it can be a particular type of claim such as construction defect. Every product is analyzed at least once during the year, with the exception of certain run-off products which are analyzed on a periodic basis. The analyses generally review losses gross of ceded reinsurance and apply the ceded reinsurance terms to the gross estimates to establish estimates net of reinsurance. In addition to the detailed analyses, CNA reviews actual loss emergence for all products each quarter.

The detailed analyses use a variety of generally accepted actuarial methods and techniques to produce a number of estimates of ultimate loss. CNA’s actuaries determine a point estimate of ultimate loss by reviewing the various estimates and assigning weight to each estimate given the characteristics of the product being reviewed. The reserve estimate is the difference between the estimated ultimate loss and the losses paid to date. The difference between the estimated ultimate loss and the case incurred loss (paid loss plus case reserve) is IBNR. IBNR calculated as such includes a provision for development on known cases (supplemental development) as well as a provision for claims that have occurred but have not yet been reported (pure IBNR).

Most of CNA’s business can be characterized as long-tail. For long-tail business, it will generally be several years between the time the business is written and the time when all claims are settled. CNA’s long-tail exposures include commercial automobile liability, workers’ compensation, general liability, medical, professional liability, other professional liability coverages, assumed reinsurance run-off and products liability. Short-tail exposures include property, commercial automobile physical damage, marine and warranty. CNA Specialty and CNA Commercial contain both long-tail and short-tail exposures. Hardy contains primarily short-tail exposures. Other contains long-tail exposures.

 

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Various methods are used to project ultimate loss for both long-tail and short-tail exposures including, but not limited to, the following:

 

   

paid development;

 

   

incurred development;

 

   

loss ratio;

 

   

Bornhuetter-Ferguson using paid loss;

 

   

Bornhuetter-Ferguson using incurred loss;

 

   

frequency times severity; and

 

   

stochastic modeling.

The paid development method estimates ultimate losses by reviewing paid loss patterns and applying them to accident or policy years with further expected changes in paid loss. Selection of the paid loss pattern may require consideration of several factors including the impact of inflation on claims costs, the rate at which claims professionals make claim payments and close claims, the impact of judicial decisions, the impact of underwriting changes, the impact of large claim payments and other factors. Claim cost inflation itself may require evaluation of changes in the cost of repairing or replacing property, changes in the cost of medical care, changes in the cost of wage replacement, judicial decisions, legislative changes and other factors. Because this method assumes that losses are paid at a consistent rate, changes in any of these factors can impact the results. Since the method does not rely on case reserves, it is not directly influenced by changes in the adequacy of case reserves.

For many products, paid loss data for recent periods may be too immature or erratic for accurate predictions. This situation often exists for long-tail exposures. In addition, changes in the factors described above may result in inconsistent payment patterns. Finally, estimating the paid loss pattern subsequent to the most mature point available in the data analyzed often involves considerable uncertainty for long-tail products such as workers’ compensation.

The incurred development method is similar to the paid development method, but it uses case incurred losses instead of paid losses. Since the method uses more data (case reserves in addition to paid losses) than the paid development method, the incurred development patterns may be less variable than paid patterns. However, selection of the incurred loss pattern typically requires analysis of all of the same factors described above. In addition, the inclusion of case reserves can lead to distortions if changes in case reserving practices have taken place, and the use of case incurred losses may not eliminate the issues associated with estimating the incurred loss pattern subsequent to the most mature point available.

The loss ratio method multiplies earned premiums by an expected loss ratio to produce ultimate loss estimates for each accident or policy year. This method may be useful for immature accident or policy periods or if loss development patterns are inconsistent, losses emerge very slowly, or there is relatively little loss history from which to estimate future losses. The selection of the expected loss ratio typically requires analysis of loss ratios from earlier accident or policy years or pricing studies and analysis of inflationary trends, frequency trends, rate changes, underwriting changes, and other applicable factors.

The Bornhuetter-Ferguson method using paid loss is a combination of the paid development method and the loss ratio method. This method normally determines expected loss ratios similar to the approach used to estimate the expected loss ratio for the loss ratio method and typically requires analysis of the same factors described above. This method assumes that future losses will develop at the expected loss ratio level. The percent of paid loss to ultimate loss implied from the paid development method is used to determine what percentage of ultimate loss is yet to be paid. The use of the pattern from the paid development method typically requires consideration of the same factors listed in the description of the paid development method. The estimate of losses yet to be paid is added to current paid losses to estimate the ultimate loss for each year. For long-tail lines, this method will react very slowly if actual

 

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ultimate loss ratios are different from expectations due to changes not accounted for by the expected loss ratio calculation.

The Bornhuetter-Ferguson method using incurred loss is similar to the Bornhuetter-Ferguson method using paid loss except that it uses case incurred losses. The use of case incurred losses instead of paid losses can result in development patterns that are less variable than paid patterns. However, the inclusion of case reserves can lead to distortions if changes in case reserving have taken place, and the method typically requires analysis of the same factors that need to be reviewed for the loss ratio and incurred development methods.

The frequency times severity method multiplies a projected number of ultimate claims by an estimated ultimate average loss for each accident or policy year to produce ultimate loss estimates. Since projections of the ultimate number of claims are often less variable than projections of ultimate loss, this method can provide more reliable results for products where loss development patterns are inconsistent or too variable to be relied on exclusively. In addition, this method can more directly account for changes in coverage that impact the number and size of claims. However, this method can be difficult to apply to situations where very large claims or a substantial number of unusual claims result in volatile average claim sizes. Projecting the ultimate number of claims may require analysis of several factors including the rate at which policyholders report claims to CNA, the impact of judicial decisions, the impact of underwriting changes and other factors. Estimating the ultimate average loss may require analysis of the impact of large losses and claim cost trends based on changes in the cost of repairing or replacing property, changes in the cost of medical care, changes in the cost of wage replacement, judicial decisions, legislative changes and other factors.

Stochastic modeling produces a range of possible outcomes based on varying assumptions related to the particular product being modeled. For some products, CNA uses models which rely on historical development patterns at an aggregate level, while other products are modeled using individual claim variability assumptions supplied by the claims department. In either case, multiple simulations are run and the results are analyzed to produce a range of potential outcomes. The results will typically include a mean and percentiles of the possible reserve distribution which aid in the selection of a point estimate.

For many exposures, especially those that can be considered long-tail, a particular accident or policy year may not have a sufficient volume of paid losses to produce a statistically reliable estimate of ultimate losses. In such a case, CNA’s actuaries typically assign more weight to the incurred development method than to the paid development method. As claims continue to settle and the volume of paid loss increases, the actuaries may assign additional weight to the paid development method. For most of CNA’s products, even the incurred losses for accident or policy years that are early in the claim settlement process will not be of sufficient volume to produce a reliable estimate of ultimate losses. In these cases, CNA will not assign any weight to the paid and incurred development methods. CNA will use the loss ratio, Bornhuetter-Ferguson and frequency times severity methods. For short-tail exposures, the paid and incurred development methods can often be relied on sooner primarily because CNA’s history includes a sufficient number of years to cover the entire period over which paid and incurred losses are expected to change. However, CNA may also use the loss ratio, Bornhuetter-Ferguson and frequency times severity methods for short-tail exposures.

For other more complex products where the above methods may not produce reliable indications, CNA uses additional methods tailored to the characteristics of the specific situation.

Periodic Reserve Reviews

The reserve analyses performed by CNA’s actuaries result in point estimates. Each quarter, the results of the detailed reserve reviews are summarized and discussed with CNA’s senior management to determine the best estimate of reserves. This group considers many factors in making this decision. The factors include, but are not limited to, the historical pattern and volatility of the actuarial indications, the sensitivity of the actuarial indications to changes in paid and incurred loss patterns, the consistency of claims handling processes, the consistency of case reserving practices, changes in CNA’s pricing and underwriting, pricing and underwriting trends in the insurance market, and legal, judicial, social and economic trends.

 

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CNA’s recorded reserves reflect its best estimate as of a particular point in time based upon known facts, consideration of the factors cited above and its judgment. The carried reserve may differ from the actuarial point estimate as the result of CNA’s consideration of the factors noted above as well as the potential volatility of the projections associated with the specific product being analyzed and other factors impacting claims costs that may not be quantifiable through traditional actuarial analysis. This process results in management’s best estimate which is then recorded as the loss reserve.

Currently, CNA’s recorded reserves are modestly higher than the actuarial point estimate. For CNA Commercial, CNA Specialty and Hardy, the difference between CNA’s reserves and the actuarial point estimate is primarily driven by uncertainty with respect to immature accident years, claim cost inflation, changes in claims handling, tort reform roll-backs which may adversely impact claim costs and the effects from the economy. For CNA’s legacy A&EP liabilities, the difference between CNA’s reserves and the actuarial point estimate is primarily driven by the potential tail volatility of run-off exposures.

The key assumptions fundamental to the reserving process are often different for various products and accident or policy years. Some of these assumptions are explicit assumptions that are required of a particular method, but most of the assumptions are implicit and cannot be precisely quantified. An example of an explicit assumption is the pattern employed in the paid development method. However, the assumed pattern is itself based on several implicit assumptions such as the impact of inflation on medical costs and the rate at which claim professionals close claims. As a result, the effect on reserve estimates of a particular change in assumptions typically cannot be specifically quantified, and changes in these assumptions cannot be tracked over time.

CNA’s recorded reserves are management’s best estimate. In order to provide an indication of the variability associated with CNA’s net reserves, the following discussion provides a sensitivity analysis that shows the approximate estimated impact of variations in significant factors affecting CNA’s reserve estimates for particular types of business. These significant factors are the ones that CNA believes could most likely materially impact the reserves. This discussion covers the major types of business for which CNA believes a material deviation to its reserves is reasonably possible. There can be no assurance that actual experience will be consistent with the current assumptions or with the variation indicated by the discussion. In addition, there can be no assurance that other factors and assumptions will not have a material impact on CNA’s reserves.

Within CNA Specialty, CNA believes a material deviation to its net reserves is reasonably possible for professional liability and related business. This business includes professional liability coverages provided to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. This business also includes D&O, employment practices, fiduciary, fidelity and surety coverages, as well as insurance products serving the health care delivery system. The most significant factor affecting reserve estimates for this business is claim severity. Claim severity is driven by the cost of medical care, the cost of wage replacement, legal fees, judicial decisions, legislative changes and other factors. Underwriting and claim handling decisions such as the classes of business written and individual claim settlement decisions can also impact claim severity. If the estimated claim severity increases by 9%, CNA estimates that the net reserves would increase by approximately $500 million. If the estimated claim severity decreases by 3%, CNA estimates that net reserves would decrease by approximately $150 million. CNA’s net reserves for this business were approximately $5.3 billion at December 31, 2012.

Within CNA Commercial, the two types of business for which CNA believes a material deviation to its net reserves is reasonably possible are workers’ compensation and general liability.

For CNA Commercial workers’ compensation, since many years will pass from the time the business is written until all claim payments have been made, claim cost inflation on claim payments is the most significant factor affecting workers’ compensation reserve estimates. Workers’ compensation claim cost inflation is driven by the cost of medical care, the cost of wage replacement, expected claimant lifetimes, judicial decisions, legislative changes and other factors. If estimated workers’ compensation claim cost inflation increases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would increase by approximately $450 million. If estimated workers’ compensation claim cost inflation decreases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would decrease

 

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by approximately $400 million. Net reserves for CNA Commercial workers’ compensation were approximately $4.9 billion at December 31, 2012.

For CNA Commercial general liability, the most significant factor affecting reserve estimates is claim severity. Claim severity is driven by changes in the cost of repairing or replacing property, the cost of medical care, the cost of wage replacement, judicial decisions, legislation and other factors. If the estimated claim severity for general liability increases by 6%, CNA estimates that its net reserves would increase by approximately $250 million. If the estimated claim severity for general liability decreases by 3%, CNA estimates that its net reserves would decrease by approximately $100 million. Net reserves for CNA Commercial general liability were approximately $3.8 billion at December 31, 2012.

Given the factors described above, it is not possible to quantify precisely the ultimate exposure represented by claims and related litigation. As a result, CNA regularly reviews the adequacy of its reserves and reassesses its reserve estimates as historical loss experience develops, additional claims are reported and settled and additional information becomes available in subsequent periods.

In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews its reserve estimates on a regular basis and makes adjustments in the period that the need for such adjustments is determined. These reviews have resulted in CNA’s identification of information and trends that have caused CNA to change its reserves in prior periods and could lead to the identification of a need for additional material increases or decreases in claim and claim adjustment expense reserves, which could materially affect our results of operations and equity and CNA’s business and insurer financial strength and corporate debt ratings positively or negatively. See the Ratings section of this MD&A for further information regarding CNA’s financial strength and corporate debt ratings.

The following table summarizes gross and net carried reserves for CNA’s property and casualty operations:

 

December 31    2012           2011  

 

 
(In millions)                   

Gross Case Reserves

   $ 8,771          $ 8,707        

Gross IBNR Reserves

     9,824            9,642        

 

 

Total Gross Carried Claim and Claim Adjustment Expense Reserves

   $    18,595          $    18,349        

 

 

Net Case Reserves

   $ 7,811          $ 7,806        

Net IBNR Reserves

     8,786            8,607        

 

 

Total Net Carried Claim and Claim Adjustment Expense Reserves

   $ 16,597          $ 16,413        

 

 

The following table summarizes the gross and net carried reserves for certain property and casualty business in run-off, including CNA Re and A&EP:

 

December 31    2012          2011  

 

 
(In millions)                  

Gross Case Reserves

   $ 1,207         $ 1,321        

Gross IBNR Reserves

     1,955           1,808        

 

 

Total Gross Carried Claim and Claim Adjustment Expense Reserves

   $      3,162         $      3,129        

 

 

Net Case Reserves

   $ 292         $ 347        

Net IBNR Reserves

     220           244        

 

 

Total Net Carried Claim and Claim Adjustment Expense Reserves

   $ 512         $ 591        

 

 

 

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Life & Group Non-Core Policyholder Reserves

CNA calculates and maintains reserves for policyholder claims and benefits for Life & Group Non-Core based on actuarial assumptions. The determination of these reserves is fundamental to its financial results and requires management to make assumptions about expected investment and policyholder experience over the life of the contract. Since many of these contracts may be in force for several decades, these assumptions are subject to significant estimation risk.

The actuarial assumptions represent management’s best estimate at the date the contract was issued plus a margin for adverse deviation. Actuarial assumptions include estimates of morbidity, mortality, policy persistency, discount rates and expenses over the life of the contracts. Under GAAP, these assumptions are locked in throughout the life of the contract unless a premium deficiency develops. The impact of differences between the actuarial assumptions and actual experience is reflected in results of operations each period.

Annually, management assesses the adequacy of its GAAP reserves by product group by performing premium deficiency testing. In this test, reserves computed using best estimate assumptions as of the date of the test without provisions for adverse deviation are compared to the recorded reserves. If reserves determined based on management’s current best estimate assumptions are greater than the existing net GAAP reserves (i.e. reserves net of any Deferred acquisition costs asset), the existing net GAAP reserves are adjusted to the greater amount.

Payout Annuity Reserves

CNA’s payout annuity reserves consist primarily of single premium group and structured settlement annuities. The annuity payments are generally fixed and are either for a specified period or contingent on the survival of the payee. These reserves are discounted except for reserves for loss adjustment expenses on structured settlements not funded by annuities in its property and casualty insurance companies. In 2012 and 2011, CNA recognized a premium deficiency on its payout annuity reserves. Therefore, the actuarial assumptions established at time of issue have been unlocked and updated to management’s then current best estimate. The actuarial assumptions that management believes are subject to the most variability are discount rates and mortality.

The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.

 

December 31, 2012    Estimated Reduction
to Pretax Income
 

 

 
(In millions of dollars)       

Hypothetical revisions

  

Discount rate:

  

50 basis point decline

     $ 131               

100 basis point decline

     277               

Mortality:

  

5% decline

     25               

10% decline

     51               

Any actual adjustment would be dependent on the specific policies affected and, therefore, may differ from the estimates summarized above.

 

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Long Term Care Reserves

Long term care policies provide benefits for nursing home, assisted living and home health care subject to various daily and lifetime caps. Policyholders must continue to make periodic premium payments to keep the policy in force. Generally CNA has the ability to increase policy premiums, subject to state regulatory approval.

CNA’s long term care reserves consist of an active life reserve, a liability for due and unpaid claims, claims in the course of settlement and incurred but not reported claims. The active life reserve represents the present value of expected future benefit payments and expenses less expected future premium.

The actuarial assumptions that management believes are subject to the most variability are discount rates, morbidity, and persistency, which can be affected by policy lapses and death. The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.

It should be noted that CNA’s current GAAP long term care reserves contain a level of margin in excess of management’s current best estimates. Any required increase in the net GAAP reserves resulting from the hypothetical revisions in the table below would first reduce the margin before they would affect results of operations. The estimated impact to results of operations in the table below are after consideration of the existing margin.

 

December 31, 2012   Estimated Reduction
to Pretax Income
 

 

 
(In millions of dollars)      

Hypothetical revisions

 

Discount rate:

 

50 basis point decline

    $ 491               

100 basis point decline

    1,221               

Morbidity:

 

5% increase

    357               

10% increase

    869               

Persistency:

 

5% decline in voluntary lapse and mortality

    208               

10% decline in voluntary lapse and mortality

    607               

Any actual adjustment would be dependent on the specific policies affected and, therefore, may differ from the estimates summarized above.

The following table summarizes the net carried Life & Group Non-Core policyholder reserves:

 

December 31, 2012   Claim and claim
adjustment expenses
         Future
     policy benefits
         Policyholders’
     funds
    Separate    
account business    
 

 

 
(In millions)                        

Long term care

    $ 1,683                $ 6,879            

Payout annuities

    637                  2,008            

Institutional markets

    1                  12           $ 100           $ 312             

Other

    45                  4            

 

 

Total (a)

    $ 2,366                $ 8,903           $ 100           $ 312             

 

 

 

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December 31, 2011   Claim and claim
adjustment expenses
         Future
     policy benefits
         Policyholders’
     funds
    Separate    
account business    
 

 

 
(In millions)                        

Long term care

    $ 1,470               $ 6,374            

Payout annuities

    660                 1,997            

Institutional markets

    1                 15           $ 129          $ 417             

Other

    53                 5            

 

 

Total (a)

    $ 2,184               $ 8,391           $ 129          $ 417             

 

 

 

(a)

Reserve amounts are net of $1.3 billion and $1.4 billion of ceded reserves and exclude $1.8 billion and $627 million of future policy benefits relating to Shadow Adjustments as of December 31, 2012 and 2011, as further discussed in Note 1 of the Notes to Consolidated Financial Statements included under Item 8. Reserves at December 31, 2012 and 2011 also exclude $162 million and $95 million of claim and claim adjustment expenses relating to Shadow Adjustments.

Results of Operations

The following table summarizes the results of operations for CNA for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8.

 

Year Ended December 31   2012     2011     2010    

 

 
(In millions)                  

Revenues:

     

Insurance premiums

  $     6,882      $     6,603      $     6,515        

Net investment income

    2,282        2,054        2,316        

Investment gains (losses)

    60        (19     86        

Other

    323        325        291        

 

 

Total

    9,547        8,963        9,208        

 

 

Expenses:

     

Insurance claims and policyholders’ benefits

    5,896        5,489        4,985        

Amortization of deferred acquisition costs

    1,274        1,176        1,168        

Other operating expenses

    1,327        1,234        1,777        

Interest

    170        185        157        

 

 

Total

    8,667        8,084        8,087        

 

 

Income before income tax

    880        879        1,121        

Income tax expense

    (247     (244     (335)      

 

 

Income from continuing operations

    633        635        786        

Discontinued operations, net

        (20)      

 

 

Net income

    633        635        766        

Amounts attributable to noncontrolling interests

    (63     (78     (129)      

 

 

Net income attributable to Loews Corporation

  $ 570      $ 557      $ 637        

 

 

2012 Compared with 2011

Net income increased $13 million in 2012 as compared with 2011. Net investment income increased $228 million, driven by significantly favorable limited partnership results. In addition, investment gains (losses) increased $79 million ($45 million after tax and noncontrolling interests). See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Insurance premiums also increased $279 million, including the acquisition of Hardy. Insurance claims and policyholders’ benefits increased $407 million, primarily due to higher catastrophe impacts, including $171 million (after tax and noncontrolling interests) from Storm Sandy, and decreased favorable net prior year development. Further information on net prior year development for 2012 and 2011 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

 

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2011 Compared with 2010

As further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August, 31, 2010, CNA completed the Loss Portfolio Transfer. We recognized a loss of $328 million (after tax and noncontrolling interests) in the third quarter of 2010, of which $309 million related to our continuing operations and $19 million related to our discontinued operations.

Net income decreased $80 million in 2011 as compared with 2010. Excluding the loss associated with the Loss Portfolio Transfer, net income decreased $408 million in 2011 as compared with 2010. Net investment income decreased $262 million, reflecting significant unfavorable limited partnership results. In addition, investment gains (losses) decreased $105 million ($56 million after tax and noncontrolling interests). See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Partially offsetting these decreases was an $88 million increase in insurance premiums. Insurance claims and policyholders’ benefits increased $504 million, primarily due to a lower level of favorable net prior year development, higher catastrophe losses and decreased results in CNA’s payout annuity business. CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, due to unlocking actuarial reserve assumptions for anticipated adverse changes in mortality and discount rates, which reflect the current low interest rate environment and CNA’s view of expected investment yields, as discussed in Life & Group Non-Core Policyholder Reserves above. Further information on net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

CNA Property and Casualty Insurance Operations

CNA’s property and casualty insurance operations consist of professional, financial, specialty property and casualty products and services and commercial insurance and risk management products.

In evaluating the results of the property and casualty businesses, CNA utilizes the loss ratio, the expense ratio, the dividend ratio and the combined ratio. These ratios are calculated using GAAP financial results. The loss ratio is the percentage of net incurred claim and claim adjustment expenses to net earned premiums. The expense ratio is the percentage of insurance underwriting and acquisition expenses, including the amortization of deferred acquisition costs, to net earned premiums. The dividend ratio is the ratio of policyholders’ dividends incurred to net earned premiums. The combined ratio is the sum of the loss, expense and dividend ratios.

The following table summarizes the results of CNA’s property and casualty operations for the years ended December 31, 2012, 2011 and 2010.

 

Year Ended December 31, 2012       CNA
    Specialty
    CNA
Commercial
          Hardy           Total            

 

 
(In millions, except %)                        

Net written premiums

  $ 2,924      $ 3,373      $ 117      $     6,414           

Net earned premiums

    2,898        3,306        120        6,324           

Net investment income

    592        854        3        1,449           

Net operating income (loss)

    453        250        (21     682           

Net realized investment gains

    12        23          35           

Net income (loss)

    465        273        (21     717           

Ratios:

       

Loss and loss adjustment expense

    63.2     77.9     60.3     70.8%      

Expense

    31.5        35.3        57.2        34.0           

Dividend

    0.1        0.3          0.2           

 

 

Combined

    94.8     113.5     117.5     105.0%      

 

 

 

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Year Ended December 31, 2011   

  CNA  

  Specialty  

     CNA
Commercial
     Total          

 

 
(In millions, except %)                     

Net written premiums

   $ 2,872           $ 3,350           $       6,222           

Net earned premiums

     2,796             3,240             6,036           

Net investment income

     500             763             1,263           

Net operating income

     465             333             798           

Net realized investment gains (losses)

     (3)            10             7           

Net income

     462             343             805           

Ratios:

        

Loss and loss adjustment expense

     59.3%          70.9%          65.5%        

Expense

     30.7             34.6             32.9           

Dividend

     (0.1)            0.3             0.1           

 

 

Combined

     89.9%          105.8%          98.5%        

 

 
Year Ended December 31, 2010                     

 

 

Net written premiums

   $ 2,691           $ 3,208           $       5,899           

Net earned premiums

     2,679             3,256             5,935           

Net investment income

     591             873             1,464           

Net operating income

     561             464             1,025           

Net realized investment gains (losses)

     18             (14)            4           

Net income

     579             450             1,029           

Ratios:

        

Loss and loss adjustment expense

     54.0%          66.8%          61.0%        

Expense

     30.6             35.4             33.3           

Dividend

     0.5             0.4             0.4           

 

 

Combined

     85.1%          102.6%          94.7%        

 

 

2012 Compared with 2011

Net written premiums increased $192 million in 2012 as compared with 2011. Net written premiums for 2012 included $117 million related to Hardy and for 2011 included $128 million related to First Insurance Company of Hawaii (“FICOH”). Excluding Hardy and FICOH, the increase in net written premiums was primarily driven by positive rate achievement, partially offset by lower new business levels in certain lines in CNA Specialty. Net earned premiums increased $288 million in 2012 as compared with 2011, including $120 million related to Hardy during 2012 and $125 million related to FICOH during 2011. Excluding Hardy and FICOH, the increase in net earned premiums was consistent with increases in net written premiums and the impact of favorable premium development in CNA Commercial in 2012 as compared to unfavorable premium development in 2011.

The CNA Specialty average rate increased 5% in 2012 as compared to flat average rate in 2011 for the policies that renewed in each period. Retention of 86% and 87% was achieved in each period. The CNA Commercial average rate increased 7% in 2012 as compared with an increase of 2% in 2011 for the policies that renewed in each period. Retention of 78% was achieved in each period.

Net operating income decreased $116 million in 2012 as compared to 2011. The decrease in net operating income was primarily due to lower favorable net prior year development, higher catastrophe losses for CNA Commercial and decreased current accident year underwriting results in CNA Specialty. These unfavorable impacts were partially offset by higher net investment income and the inclusion of the Surety business on a wholly owned basis in 2012 for CNA Specialty. Catastrophe losses were $243 million (after tax and noncontrolling interests) in 2012 as compared to $130 million (after tax and noncontrolling interests) in 2011.

 

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The combined ratio increased 6.5 points in 2012 as compared to 2011. The loss ratio increased 5.3 points in 2012 as compared to 2011, primarily due to higher catastrophe losses in CNA Commercial, lower favorable net prior year development and a higher current accident year loss ratio. The expense ratio increased by 1.1 points, primarily due to the favorable impact of recoveries in 2011 on insurance receivables written off in prior years in CNA Commercial and increased acquisition and underwriting expenses in CNA Specialty.

Favorable net prior year development decreased by $189 million, from $428 million in 2011 to $239 million in 2012. Further information on net prior year development for 2012 and 2011 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

2011 Compared with 2010

Net written premiums increased $323 million in 2011 as compared with 2010, primarily driven by new business, positive rate achievement in CNA Commercial, improved economic conditions reflected in insured exposures, as well as lower reinsurance costs. Net earned premiums increased $101 million in 2011 as compared with 2010, consistent with increases in net written premiums over recent quarters and favorable premium development in CNA Specialty, partially offset by unfavorable premium development in CNA Commercial.

The average rate for CNA Specialty was flat for 2011 as compared to a decrease of 2% in 2010 for the policies that renewed in each period. Retention of 87% and 86% was achieved in each period. The average rate for CNA Commercial increased 2% in 2011 as compared with an increase of 1% in 2010 for the policies that renewed in each period. Retention of 78% and 80% was achieved in each period.

Net operating income decreased $227 million in 2011 as compared to 2010 primarily due to lower net investment income, higher catastrophe losses and lower favorable net prior year development. Catastrophe losses were $130 million (after tax and noncontrolling interests) in 2011 as compared to $71 million (after tax and noncontrolling interests) in 2010.

The combined ratio increased 3.8 points in 2011 as compared to 2010. The loss ratio increased 4.5 points in 2011 as compared to 2010, primarily due to lower favorable net prior year development and higher catastrophe losses. The expense ratio improved by 0.4 points, primarily due to the favorable impact of recoveries in 2011 on insurance receivables written off in prior years in CNA Commercial.

Favorable net prior year development decreased by $172 million, from $600 million in 2010 to $428 million in 2011. Further information on net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

Life & Group Non-Core and Other Operations

Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. Other primarily includes certain CNA corporate expenses, including interest on corporate debt and the results of certain property and casualty business in run-off, including CNA Re and A&EP. In 2010, CNA ceded substantially all of its legacy A&EP liabilities under the Loss Portfolio Transfer, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.

 

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The following table summarizes the results of CNA’s Life & Group Non-Core and Other operations for the years ended December 31, 2012, 2011 and 2010.

 

Year Ended December 31, 2012    Life & Group
Non-Core
           Other               Total         

 

 
(In millions)                    

Net earned premiums

   $ 560               $ 560          

Net investment income

     801             $ 32        833          

Net loss

     (81)              (66     (147)         
Year Ended December 31, 2011                    

 

 

Net earned premiums

   $ 569               $ 569          

Net investment income

     759             $ 32        791          

Net operating loss

     (187)              (44     (231)         

Net realized investment losses

     (4)              (13     (17)         

Net loss

     (191)              (57     (248)         
Year Ended December 31, 2010                    

 

 

Net earned premiums

   $ 582               $ 582          

Net investment income

     715             $ 137        852          

Net operating loss

     (81)              (334     (415)         

Net realized investment gains

     30               12        42          

Net loss

     (51)              (322     (373)         

 

 

2012 Compared with 2011

Net earned premiums, which relate primarily to the individual and group long term care businesses, decreased $9 million in 2012 as compared with 2011, primarily due to lapsing of policies in CNA’s individual long term care business, which is in run-off, partially offset by increased premiums resulting from rate increase actions related to this business.

Net loss decreased $101 million in 2012 as compared with 2011. The results include expenses of $22 million (after tax and noncontrolling interests) in 2012 and $104 million (after tax and noncontrolling interests) in 2011 related to CNA’s payout annuity business, due to unlocking actuarial reserve assumptions. The initial reserving assumptions for these contracts were determined at issuance, including a margin for adverse deviation, and were locked in throughout the life of the contract unless a premium deficiency developed. The increase to the related reserves in 2012 related to anticipated adverse changes in discount rates, which reflect the current low interest rate environment and CNA’s view of expected future investment yields. The increase in 2011 related to anticipated adverse changes in mortality and discount rates. Additionally, long term care claim reserves were increased $18 million (after tax and noncontrolling interests) in 2012 and $30 million (after tax and noncontrolling interests) in 2011.

The decrease in net loss was also driven by improved results in Life & Group Non-Core life settlement contracts business and the impact of unfavorable performance in 2011 on its remaining pension deposit business.

2011 Compared with 2010

Net earned premiums, which relate primarily to the individual and group long term care businesses, decreased $13 million in 2011 as compared with 2010.

Net loss decreased $125 million in 2011 as compared with 2010, primarily driven by the loss of $328 million (after tax and noncontrolling interests) as a result of the Loss Portfolio Transfer consummated in the third quarter of 2010. As a result of that transaction, the investment income allocated to Other decreased substantially because of the lower net reserve base and associated risk capital.

 

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These net loss decreases were partially offset by net loss increases in CNA’s payout annuity, pension deposit and long term care businesses. In 2011, CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, as discussed above. In 2010, CNA’s payout annuity reserves were increased by $35 million (after tax and noncontrolling interests), resulting from unlocking assumptions. Additionally, long term care claim reserves were increased by $30 million (after tax and noncontrolling interests) in 2011.

A number of CNA’s separate account pension deposit contracts guarantee principal and an annual minimum rate of interest. If aggregate contract value in the separate account exceeds the fair value of the related assets, an additional Policyholders’ funds liability is established. In 2011, CNA increased this pretax liability by $18 million. In 2010, CNA decreased this pretax liability by $24 million.

Diamond Offshore

Diamond Offshore’s operating income is primarily a function of contract drilling revenue earned less contract drilling expenses incurred or recognized. The two most significant variables affecting Diamond Offshore’s revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. These factors are not within Diamond Offshore’s control and are difficult to predict. Revenue from dayrate drilling contracts are generally recognized as services are performed, consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, Diamond Offshore may receive fees for the mobilization of equipment. In addition, some of Diamond Offshore’s drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which it may be compensated.

Diamond Offshore’s operating income is also a function of varying levels of operating expenses. Operating expenses generally are not affected by changes in dayrates, and short term reductions in utilization do not necessarily result in lower operating expenses. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm stacked” state with a full crew. In addition, when a rig is idle, Diamond Offshore is responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, Diamond Offshore may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income.

Operating expenses represent all direct and indirect costs associated with the operation and maintenance of Diamond Offshore’s drilling equipment. The principal components of Diamond Offshore’s operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of Diamond Offshore’s operating expenses. In general, labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which Diamond Offshore’s rigs operate. In addition, the costs associated with training new and seasoned employees can be significant. Diamond Offshore expects its labor and training costs to increase in 2013 as a result of increased hiring and training activities as it continues the process of crewing its four new drillships. Costs to repair and maintain equipment fluctuate depending upon the type of activity the drilling rig is performing, as well as the age and condition of the equipment and the regions in which Diamond Offshore’s rigs are working.

Operating income is negatively impacted when Diamond Offshore performs certain regulatory inspections, which it refers to as a 5-year survey, or special survey, that are due every five years for each of Diamond Offshore’s rigs. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs which are recognized as incurred. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.

 

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In addition, operating income may also be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the United Kingdom (“U.K.”) and Norwegian sectors of the North Sea.

As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, Diamond Offshore expects contract drilling revenue in 2013 to decline from the levels attained in 2012. During 2013, 11 of Diamond Offshore’s rigs will require 5-year surveys and one of its U.K. rigs will require dry-docking for inspections. These 12 rigs will be out of service for approximately 830 days in the aggregate. Diamond Offshore also expects to spend an additional approximately 590 days during 2013 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects, including contract preparation work for the Ocean Endeavor and North Sea enhancements for the Ocean Patriot, each of which is expected to require approximately 180 days of downtime. Diamond Offshore can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects.

Diamond Offshore is self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to Diamond Offshore’s rigs or equipment, it could have a material adverse effect on its financial condition, results of operations and cash flows. Under its insurance policy that expires on May 1, 2013, Diamond Offshore carries physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which its deductible for physical damage is $25 million per occurrence. Diamond Offshore does not typically retain loss-of-hire insurance policies to cover its rigs.

In addition, under its current insurance policy, Diamond Offshore carries marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. Diamond Offshore believes that the policy limit for its marine liability insurance is within the range that is customary for companies of its size in the offshore drilling industry and is appropriate for Diamond Offshore’s business. Diamond Offshore’s deductibles for marine liability coverage, including for personal injury claims, are $10 million for the first occurrence and vary in amounts ranging between $5 million and, if aggregate claims exceed certain thresholds, up to $100 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year.

Recent Developments

Internationally, the ultra-deepwater and deepwater floater markets are generally strong and continue to show signs of further strengthening, particularly for ultra-deepwater rigs where there are reportedly few, if any, uncontracted rigs available to work in 2013, inclusive of the expected 2013 newbuild deliveries, with the market expected to remain strong throughout 2013. Diamond Offshore believes that the diminished availability of rigs in this market could continue to put upward pressure on dayrates during 2013. However, due to its contracted backlog in 2013 (100% and 92% for its ultra-deepwater and deepwater fleets), Diamond Offshore has limited availability in this market and may not be able to benefit from higher price fixtures during that period. Newbuild orders for ultra-deepwater and deepwater floaters continued to be placed in 2012, including Diamond Offshore’s order for a fourth drillship and a semisubmersible rig, both of which are currently under construction. Based on recent analyst data, there are 67 floater rigs, primarily ultra-deepwater and deepwater units, on order or under construction, excluding an estimated 29 rigs to be built on behalf of Petróleo Brasileiro S.A., (“Petrobras”), which is currently Diamond Offshore’s most significant customer. Excluding Petrobras’ ordered rigs, nearly 73% of the floaters scheduled for delivery in 2014 and beyond are not yet contracted for future work, including two of Diamond Offshore’s drillships and one of its semisubmersible rigs under construction. In addition, Petrobras has recently announced that it plans to cap the number of its contracted deepwater rigs beginning in 2016. According to industry analysts, they believe Petrobras intends to fill the majority of its deepwater requirement with its own rigs, which are not yet under construction but which are scheduled for delivery in 2015 and beyond, although industry analysts believe that this timing may be delayed due to current Brazilian shipyard limitations. If imposed by Petrobras, this limit on the

 

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number of contracted rigs could lead to additional availability and increased competition in the deepwater market in the future.

Market demand for mid-water floaters is generally stable and is also strengthening in certain geographic markets. In both the U.K. and Norway sectors of the North Sea, the mid-water market is very strong with industry analysts predicting the next availability of rigs in late 2013. A 2012 discovery offshore Norway has resulted in increased interest in the harsh North Sea region, where there is a limited number of rigs capable of working and the barriers to entry are high, primarily due to significant rig modifications necessary to operate in the region. In February of 2013, Diamond Offshore announced its plan to upgrade one of its mid-water floaters for North Sea operations, with a minimum three-year contract for the upgraded rig in the U.K. sector of the North Sea beginning in 2014. In the Mediterranean region, demand remains solid, including the Black Sea region where recent gas discoveries have led to increased interest in the region. The Southeast Asia and Australia markets also remain steady with indications of possible strengthening.

Four of Diamond Offshore’s marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Diamond Offshore’s other international jack-up commenced a two year bareboat charter offshore Ecuador in 2012. During 2012, Diamond Offshore sold six jack-up rigs, resulting in a pretax gain of approximately $76 million.

Drilling activity on the Outer Continental Shelf of the GOM has continued to strengthen and has surpassed pre-Macondo levels. Additionally, some industry analysts predict that drilling activity, particularly in the ultra-deepwater market, will continue to strengthen in 2013 and beyond. However, Diamond Offshore’s ability to meet this demand is limited in the near term. Diamond Offshore currently has two semisubmersible rigs on contract in the GOM, one of which is expected to have limited availability in the second half of 2013. It also has one mid-water floater and one jack-up rig there available for contract. Looking forward, Diamond Offshore’s two ultra-deepwater drillships as well as one semisubmersible rig under construction which are scheduled for delivery in 2014, none of which have been contracted and could be positioned in this market. The Ocean Onyx which is currently under construction, is expected to commence a one-year contract plus potential option periods in the GOM during the third quarter of 2013.

Contract Drilling Backlog

The following table reflects Diamond Offshore’s contract drilling backlog as of February 1, 2013, October 17, 2012 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012) and February 1, 2012 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2011). Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Diamond Offshore’s calculation also assumes full utilization of its drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92% – 98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in Diamond Offshore’s contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

 

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     February 1,
2013
     October 17,
2012
     February 1,     
2012     
 

 

 
(In millions)                     

Floaters:

        

Ultra-Deepwater (a)

   $ 4,422          $ 4,660          $ 4,926         

Deepwater (b)

     1,229            1,373            1,081         

Mid-Water (c)

     2,649            2,510            2,348         

 

 

Total Floaters

     8,300            8,543            8,355         

Jack-ups

     272            203            277         

 

 

Total

   $ 8,572          $ 8,746          $ 8,632         

 

 

 

(a)

As of February 1, 2013, for ultra-deepwater floaters includes (i) $1.3 billion attributable to contracted operations offshore Brazil for the years 2013 to 2015 and (ii) $1.8 billion attributable to future work for two drillships under construction for the years 2013 to 2019.

(b)

As of February 1, 2013, for deepwater floaters includes (i) $563 million attributable to contracted operations offshore Brazil for the years 2013 to 2016 and (ii) $179 million for the years 2013 to 2014 attributable to future work for the Ocean Onyx, which is under construction.

(c)

As of February 1, 2013, for mid-water floaters includes $880 million attributable to contracted operations offshore Brazil for the years 2013 to 2015.

The following table reflects the amount of Diamond Offshore’s contract drilling backlog by year as of February 1, 2013:

 

Year Ended December 31    Total      2013      2014      2015      2016 – 2019    

 

 
(In millions)                                   

Floaters:

              

Ultra-Deepwater (a)

   $ 4,422       $ 979       $ 1,223       $ 996           $ 1,224       

Deepwater (b)

     1,229         569         456         142         62       

Mid-Water (c)

     2,649         1,106         955         408         180       

 

 

Total Floaters

     8,300         2,654         2,634         1,546         1,466       

Jack-ups

     272         140         72         48         12       

 

 

Total

   $     8,572       $     2,794       $     2,706       $     1,594           $ 1,478       

 

 

 

(a)

As of February 1, 2013, for ultra-deepwater floaters includes (i) $524 million, $473 million and $324 million for the years 2013 to 2015, attributable to contracted operations offshore Brazil and (ii) $29 million, $299 million and $361 million for the years 2013 to 2015, and $1.1 billion in the aggregate for the years 2016 to 2019, attributable to future work for two drillships under construction.

(b)

As of February 1, 2013, for deepwater floaters includes (i) $218 million, $149 million, $134 million and $62 million for the years 2013 to 2016, attributable to contracted operations offshore Brazil and (ii) $45 million and $134 million for the years 2013 and 2014, attributable to future work for the Ocean Onyx, which is under construction.

(c)

As of February 1, 2013, for mid-water floaters includes $456 million, $342 million and $82 million for the years 2013 to 2015, attributable to contracted operations offshore Brazil.

 

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The following table reflects the percentage of rig days committed by year as of February 1, 2013. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in Diamond Offshore’s fleet, to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning dates for rigs under construction.

 

Year Ended December 31    2013 (a)        2014 (a)        2015 (a)        2016 - 2019    

 

 

Floaters:

           

Ultra-Deepwater

     100%         86%         57%         14%       

Deepwater

     92%         44%         15%         2%       

Mid-Water

     72%         50%         18%         2%       

Total Floaters

     83%         60%         30%         6%       

Jack-ups

     69%         39%         20%         1%       

 

(a)

As of February 1, 2013, includes approximately 1,540, 660 and 140 currently known, scheduled shipyard, survey and mobilization days for 2013, 2014 and 2015.

Dayrate and Utilization Statistics

 

Year Ended December 31      2012                  2011                2010      

 

 

Revenue earning days (a)

                    

Floaters:

                    

Ultra-Deepwater

     2,475               2,387               1,873        

Deepwater

     1,605               1,718               1,342        

Mid-Water

     4,639               5,254               5,800        

Jack-ups (b)

     1,753               2,218               3,028        

Utilization (c)

                    

Floaters:

                    

Ultra-Deepwater

     85%               82%               66%        

Deepwater

     88%               94%               74%        

Mid-Water

     68%               72%               79%        

Jack-ups (d)

     53%               47%               61%        

Average daily revenue (e)

                    

Floaters:

                    

Ultra-Deepwater

   $   354,900             $   342,900             $   358,400        

Deepwater

     368,800               416,500               401,900        

Mid-Water

     263,600               269,600               281,000        

Jack-ups

     90,200               81,900               87,700        

 

(a)

A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

(b)

Revenue earning days for the years ended December 31, 2012, 2011 and 2010 included approximately 87 days, 720 days and 1,167 days, earned by Diamond Offshore’s jack-up rigs during the respective periods prior to being sold in 2012 and 2010.

(c)

Utilization is calculated as the ratio of total revenue earnings days divided by the total calendar days in the period for all rigs in Diamond Offshore’s fleet (including cold stacked rigs).

(d)

Utilization for Diamond Offshore’s jack-up rigs would have been 87%, 59% and 73% for the years ended December 31, 2012, 2011 and 2010, excluding revenue earning days and total calendar days associated with rigs that were sold in 2012 and 2010.

(e)

Average daily revenue is defined as contract drilling revenue (excluding revenue for mobilization, demobilization and contract preparation) per revenue earning day.

 

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Results of Operations

The following table summarizes the results of operations for Diamond Offshore for the years ended December 31, 2012, 2011 and 2010 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:

 

Year Ended December 31    2012          2011          2010        

 

 
(In millions)                             

Revenues:

            

Contract drilling revenues

   $       2,936         $       3,254         $ 3,230        

Net investment income

     5           7           3        

Investment gains

          1        

Other

     131           73           128        

 

 

Total

     3,072           3,335           3,361        

 

 

Expenses:

            

Contract drilling expenses

     1,537           1,549           1,391        

Other operating expenses

     572           535           546        

Interest

     46           73           91        

 

 

Total

     2,155           2,157           2,028        

 

 

Income before income tax

     917           1,178           1,333        

Income tax expense

     (223        (250        (413)       

Amounts attributable to noncontrolling interests

     (357        (477        (474)       

 

 

Net income attributable to Loews Corporation

   $ 337         $ 451         $ 446        

 

 

2012 Compared with 2011

Contract drilling revenue decreased $318 million and net income decreased $114 million in 2012 as compared with 2011. Contract drilling revenue for 2012 was negatively impacted by a decrease in both revenue earning days and average daily revenue earned by Diamond Offshore’s deepwater and mid-water floaters, partially offset by favorable revenue variances for its ultra-deepwater floaters. Contract drilling expense decreased $12 million primarily due to a decrease in expense for mid-water floaters and jack-ups due to the movement of certain rigs to other operating regions with lower cost structures, lower repair and inspection costs, as well as the absence of operating costs in 2012 for the recently sold jack-up rigs. The decrease in contract drilling expense was partially offset by an increase in costs associated with ultra-deepwater and deepwater floaters, primarily due to higher personnel related, inspection and shorebase support costs in 2012.

Revenue generated by ultra-deepwater floaters increased $61 million in 2012 as compared with 2011, primarily due to increased average daily revenue of $30 million and increased utilization of $30 million due to higher revenue earning days. The increase in average daily revenue is primarily due to higher dayrates earned by the Ocean Monarch operating internationally during 2012 compared with the rig operating in the GOM in 2011. The increase in revenue earning days is primarily due to downtime associated with the Ocean Monarch in 2011, partially offset by a decrease in revenue earning days in 2012 for other ultra-deepwater rigs as a result of scheduled surveys and shipyard projects as well as unscheduled downtime for repairs in 2012.

Revenue generated by deepwater floaters decreased $135 million in 2012 as compared with 2011, primarily due to a $76 million decrease in average daily revenue, a $47 million decrease in utilization as a result of fewer revenue earning days and a $12 million decrease in amortized mobilization fees. The decline in average daily revenue during 2012 is primarily due to the completion of the Ocean Valiant’s contract in Angola in December of 2011 which was at a significantly higher dayrate than the rig earned during 2012. The decrease in utilization during 2012 is primarily due to higher incremental downtime for s