10-K 1 d620046d10k.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, 2013

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

incorporation or organization)

   

(I.R.S. Employer    

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 $13,578,000,000.

As of February 14, 2014, there were 387,403,380 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, 2014 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, 2013

 

Item         Page  
No.    PART I    No.  
  1   

Business

  
  

CNA Financial Corporation

     3   
  

Diamond Offshore Drilling, Inc.

     8   
  

Boardwalk Pipeline Partners, LP

     12   
  

HighMount Exploration & Production LLC

     15   
  

Loews Hotels Holding Corporation

     21   
  

Executive Officers of the Registrant

     22   
  

Available Information

     23   
  1A   

Risk Factors

     23   
  1B   

Unresolved Staff Comments

     46   
  2   

Properties

     46   
  3   

Legal Proceedings

     46   
  4   

Mine Safety Disclosures

     46   
   PART II   
  5   

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

     47   
  6   

Selected Financial Data

     49   
  7   

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

     50   
  7A   

Quantitative and Qualitative Disclosures about Market Risk

     98   
  8   

Financial Statements and Supplementary Data

     102   
  9   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     182   
  9A   

Controls and Procedures

     182   
  9B   

Other Information

     182   
   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

     183   

 

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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 53% 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 a chain 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 21 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 67.2%, 65.6% and 63.4% of our consolidated total revenue for the years ended December 31, 2013, 2012 and 2011.

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:

Management & Professional Liability:  Management & Professional 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 other professional firms. Management & Professional Liability also provides directors and officers (“D&O”), employment practices, fiduciary and fidelity coverages. Specific areas of focus include small and mid-size firms, public as well as privately

 

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held firms and not-for-profit organizations, where tailored products for these client segments are offered. Products within Management & Professional Liability are distributed through brokers, independent agents and managing general underwriters. Management & Professional Liability, through CNA HealthPro, also offers insurance products to serve the health care industry. Products include professional and general liability as well as 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 aging services, allied medical facilities, life sciences, dentists, doctors, hospitals, and nurses and other medical practitioners.

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 interests 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. CNA also provides specialized insurance to customers who are generally viewed as higher risk and less predictable in exposure than those covered by standard insurance markets. 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”).

Hardy

Hardy Underwriting Bermuda Limited (“Hardy”) is 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.

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.

 

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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”).

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      2013              2012              2011            

 

 

California

       9.2%           9.5%           9.4%       

Texas

       8.0               7.4               6.7           

New York

       7.3               7.1               6.7           

Illinois

       5.9               6.5               4.9           

Florida

       5.9               5.8               6.1           

New Jersey

       3.7               3.5               3.5           

Pennsylvania

       3.7               3.4               3.4           

Canada

       3.1               3.0               3.0           

All other states, countries or political subdivisions

       53.2               53.8               56.3           

 

 
       100.0%           100.0%           100.0%       

 

 

Approximately 8.9%, 9.2% and 8.8% of CNA’s direct written premiums were derived from outside of the United States for the years ended December 31, 2013, 2012 and 2011.

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.

 

     Schedule of Loss Reserve Development  

 

 
Year Ended December 31    2003      2004      2005      2006      2007      2008      2009      2010(a)       2011      2012(b)      2013  

 

 
(In millions of dollars)                                                                             

Originally reported gross reserves for unpaid claim and claim adjustment expenses

     31,284          31,204          30,694          29,459          28,415          27,475          26,712         25,412          24,228         24,696            24,015    

Originally reported ceded recoverable

     13,847          13,682          10,438          8,078          6,945          6,213          5,524         6,060          4,967         5,075            4,911    

 

 

Originally reported net reserves for unpaid claim and claim adjustment expenses

     17,437          17,522          20,256          21,381          21,470          21,262          21,188         19,352          19,261         19,621            19,104    

 

 

Cumulative net paid as of:

                                

One year later

     4,382          2,651          3,442          4,436          4,308          3,930          3,762         3,472          4,277         4,588              

Two years later

     6,104          4,963          7,022          7,676          7,127          6,746          6,174         6,504          7,459         -              

Three years later

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

Four years later

     10,085          9,914          11,289          11,312          10,121          9,863          10,038                 -         -              

Five years later

     11,834          11,261          12,465          11,973          11,262          11,115          -                 -         -              

Six years later

     12,988          12,226          12,917          12,858          12,252                  -                 -         -              

Seven years later

     13,845          12,551          13,680          13,670                          -                 -         -              

Eight years later

     14,073          13,245          14,409                                  -                 -         -              

Nine years later

     14,713          13,916                                          -                 -         -              

Ten years later

     15,337                                                  -                 -         -              

Net reserves re-estimated as of:

                                

End of initial year

     17,437          17,522          20,256          21,381          21,470          21,262          21,188         19,352          19,261         19,621            19,104    

One year later

     17,671          18,513          20,588          21,601          21,463          21,021          20,643         18,923          19,081         19,506              

Two years later

     19,120          19,044          20,975          21,706          21,259          20,472          20,237         18,734          18,946         -              

Three years later

     19,760          19,631          21,408          21,609          20,752          20,014          20,012         18,514          -         -              

Four years later

     20,425          20,212          21,432          21,286          20,350          19,784          19,758                 -         -              

Five years later

     21,060          20,301          21,326          20,982          20,155          19,597          -                 -         -              

Six years later

     21,217          20,339          21,060          20,815          20,021                  -                 -         -              

Seven years later

     21,381          20,142          20,926          20,755                          -                 -         -              

Eight years later

     21,199          20,023          20,900                                  -                 -         -              

Nine years later

     21,100          20,054                                          -                 -         -              

Ten years later

     21,135                                                  -                 -         -              

 

 

Total net (deficiency) redundancy

     (3,698)         (2,532)         (644)         626          1,449          1,665          1,430         838          315         115              

 

 

Reconciliation to gross re-estimated reserves:

                                

Net reserves re-estimated

     21,135         20,054         20,900         20,755         20,021         19,597         19,758        18,514         18,946        19,506              

Re-estimated ceded recoverable

     15,852         14,706         12,025         9,697         8,293         7,252         6,593        7,093         5,850        5,531              

 

 

Total gross re-estimated reserves

     36,987         34,760         32,925         30,452         28,314         26,849         26,351        25,607         24,796        25,037              

 

 

Total gross (deficiency) redundancy

     (5,703)        (3,556)        (2,231)        (993)        101        626         361        (195)         (568)         (341)             

 

 

Net (deficiency) redundancy related to:

                                

Asbestos

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

Environmental pollution

     (209)        (209)         (159)         (159)         (159)         (76)         -                 -         -              

 

 

Total asbestos and environmental pollution

     (386)        (332)         (272)         (271)         (266)         (155)         -                 -         -              

Core (Non-asbestos and environmental pollution)

     (3,312)        (2,200)        (372)        897         1,715         1,820         1,430        838         315        115              

 

 

Total net (deficiency) redundancy

     (3,698)        (2,532)        (644)        626         1,449         1,665         1,430        838         315        115              

 

 

 

(a)

Effective January 1, 2010, CNA ceded its net asbestos and environmental pollution claim and allocated claim adjustment expense reserves under a retroactive reinsurance agreement as further discussed in Note 9 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.

 

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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 9 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 2012 statutory net written premiums, CNA is the eighth 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 currently directly regulate the business of insurance, federal legislative and regulatory initiatives can impact the insurance industry. These initiatives and legislation include proposed federal oversight of certain insurers; tort reform proposals; proposals addressing natural catastrophe exposures; terrorism risk mechanisms; federal financial services reforms; and various tax proposals affecting insurance companies. Any of the foregoing regulatory limitations, impositions and restrictions may result in significant burdens on CNA.

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.

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:

 

    Size              
Location   (square feet)      Principal Usage

 

333 S. Wabash Avenue

  639,553                 Principal executive offices of CNA

Chicago, Illinois

      

2405 Lucien Way

  113,084                 Property and casualty insurance offices

Maitland, Florida

      

125 S. Broad Street

  71,847                 Property and casualty insurance offices

New York, New York

      

101 S. Reid Street

  61,631                 Property and casualty insurance offices

Sioux Falls, South Dakota

      

4150 N. Drinkwater Boulevard

  56,281                 Property and casualty insurance offices

Scottsdale, Arizona

      

401 Penn Street

  56,009                 Property and casualty insurance offices

Reading, Pennsylvania

      

10375 Park Meadows Drive

  42,968                 Property and casualty insurance offices

Littleton, Colorado

      

675 Placentia Avenue

  41,340                 Property and casualty insurance offices

Brea, California

      

700 N. Pearl Street

  37,870                 Property and casualty insurance offices

Dallas, Texas

      

1249 S. River Road

  36,946                 Property and casualty insurance offices

Cranbury, New Jersey

      

CNA leases its office space described above except for the building in Chicago, Illinois, which is 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 19.4%, 21.1% and 23.6% of our consolidated total revenue for the years ended December 31, 2013, 2012 and 2011.

Rigs:   Diamond Offshore owns 45 offshore drilling rigs, consisting of 33 semisubmersible rigs, seven jack-ups and five dynamically positioned drillships, three of which are under construction with deliveries scheduled for the second and third quarters of 2014 and the first quarter of 2015. Diamond Offshore’s semisubmersible fleet also includes the Ocean Apex, a moored semisubmersible rig which is under construction and expected to be delivered in the third quarter of 2014, a mid-water floater which is being modified to work in the North Sea, to be completed in the second quarter of 2014 and a dynamically positioned, ultra-deepwater harsh environment semisubmersible

 

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drilling rig, under construction, expected to be delivered in the first quarter of 2016. 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    13  (b)            

Deepwater

   5,000    to      7,500      7  (c)            

Mid-Water

      400    to      4,999    18                  

 

(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 various conditions (such as salinity of the ocean, weather and sea conditions).

(b)

Includes three drillships and one harsh environment semisubmersible rig under construction.

(c)

Includes one rig under construction utilizing the hull of one of Diamond Offshore’s existing mid-water floaters.

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 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. Since 2009, commencing with the acquisition of two newbuild, ultra-deepwater semisubmersible rigs, Diamond Offshore has committed over $5 billion towards upgrading its fleet. The Ocean Onyx, one of its two newest deepwater semisubmersible rigs, was completed in late 2013 and commenced drilling operations under a one-year contract in the Gulf of Mexico (“GOM”) in early 2014. The Ocean BlackHawk, the first of four new ultra-deepwater drillships, is currently mobilizing to the GOM and is expected to begin working under contract in the second quarter of 2014. Diamond Offshore also has six other construction/enhancement projects underway including:

 

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three dynamically positioned, ultra-deepwater drillships with expected completion dates in the second and third quarters of 2014 and the first quarter of 2015 at an aggregate cost of approximately $1.9 billion;

 

   

a dynamically positioned, ultra-deepwater harsh environment semisubmersible drilling rig with an expected completion date in the first quarter of 2016 at an estimated cost of approximately $755 million;

 

   

a deepwater semisubmersible rig with an expected completion date in the third quarter of 2014 at an estimated cost of approximately $370 million; and

 

   

enhancements to a mid-water semisubmersible rig that will enable the rig to work in the North Sea with an expected completion date in the second quarter of 2014 at an estimated cost of approximately $120 million.

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

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

 

   

South America, principally offshore Brazil and Trinidad and Tobago;

 

   

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

 

   

the Middle East;

 

   

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

 

   

East and West Africa;

 

   

the Mediterranean; 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 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.

 

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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 2013, 2012 and 2011, Diamond Offshore performed services for 39, 35 and 52 different customers. During 2013, 2012 and 2011, 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 34%, 33% and 35% of Diamond Offshore’s annual total consolidated revenues. OGX Petróleo e Gás Ltda. (“OGX”), (a privately owned Brazilian oil and natural gas company that filed for bankruptcy in October of 2013), accounted for 2%, 12% and 14% of Diamond Offshore’s annual total consolidated revenues in each of the years ended December 31, 2013, 2012 and 2011. No other customer accounted for 10% or more of Diamond Offshore’s annual total consolidated revenues during 2013, 2012 or 2011.

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 ten rigs contracted. Diamond Offshore’s contract backlog attributable to its expected operations offshore Brazil is $953 million, $537 million and $62 million for the years 2014, 2015 and 2016.

Competition:  Despite consolidation in previous 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 approximately 600 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.

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.

 

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Operations Outside the United States:  Diamond Offshore’s operations outside the U.S. accounted for approximately 89%, 94% and 90% of its total consolidated revenues for the years ended December 31, 2013, 2012 and 2011.

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, Angola, Vietnam, Thailand, Cameroon, Trinidad and Tobago 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 8.2%, 8.1% and 8.1% of our consolidated total revenue for the years ended December 31, 2013, 2012 and 2011.

We own approximately 53% of Boardwalk Pipeline comprised of 125,586,133 common 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.

Boardwalk Pipeline owns and operates approximately 14,195 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 255 miles of NGL pipelines in Louisiana. In 2013, its pipeline systems transported approximately 2.4 trillion cubic feet (“Tcf”) of natural gas and approximately 7.5 million barrels (“MMbbls”) of NGLs. Average daily throughput on Boardwalk Pipeline’s natural gas pipeline systems during 2013 was approximately 6.6 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 207.0 Bcf and Boardwalk Pipeline’s NGL storage facilities consist of eight salt dome storage caverns located in Louisiana 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 storage 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, 2013 was 1.2 Bcf per day.

The Gulf South pipeline system runs approximately 7,200 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 6.9 Bcf per day and average daily throughput for the year ended December 31, 2013 was 2.5 Bcf per day.

The Texas Gas pipeline system originates in Louisiana, East Texas and Arkansas and runs for approximately 6,100 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 4.6 Bcf per day and average daily throughput for the year ended December 31, 2013 was 2.6 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 primarily in south Texas with approximately 420 miles of pipeline.

 

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Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage Company, LLC) (“Petal”) owns and operates eight salt dome natural gas storage caverns in Mississippi, with 46.0 Bcf of total storage capacity, of which approximately 29.0 Bcf is working gas capacity. Petal also operates approximately 100 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, 2013 was 0.2 Bcf per day. Petal also owns undeveloped land which is suitable for up to five additional storage caverns.

Louisiana Midstream’s storage services provide approximately 57.8 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 approximately 270 miles of pipeline assets, including an extensive ethylene distribution system.

Boardwalk Pipeline’s current growth projects and investments include the following:

Southeast Market Expansion: The Southeast Market Expansion project is an interconnection between Boardwalk Pipeline’s Gulf South pipeline and Petal facilities, additional compression facilities and approximately 70 miles of additional pipeline, adding 0.5 Bcf per day of peak-day transmission capacity. The project, which was approved by the Federal Energy Regulatory Commission (“FERC”), is expected to be placed in service in the fourth quarter 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.

Ohio to Louisiana Access Project: Boardwalk Pipeline’s Ohio to Louisiana Access Project would provide long term firm natural gas transportation from the Marcellus and Utica production areas to Louisiana. This project does not add additional capacity to Boardwalk Pipeline’s natural gas pipeline systems, but will reverse the traditional flow of natural gas from northbound to southbound on a portion of its Texas Gas system. The project is supported by firm transportation contracts for 0.6 Bcf of capacity per day with producers and end-users with a weighted average contract life of approximately 13 years. The project is expected to cost approximately $115 million and is expected to be placed into service in the first half of 2016, subject to FERC approval.

Bluegrass Project: In 2013, Boardwalk Pipeline executed a series of agreements with the Williams Companies, Inc. (“Williams”) to develop the Bluegrass Project, a joint venture project that would develop a pipeline to transport NGLs from the Marcellus and Utica shale plays to the petrochemical and export complex in the Lake Charles, Louisiana area, and the construction of related fractionation, storage and liquefied petroleum gas (“LPG”) terminal export facilities.

The proposed project would include constructing a new pipeline that would initially provide producers with 200,000 barrels per day of mixed NGLs take-away capacity in Ohio, West Virginia and Pennsylvania to an interconnect with the Texas Gas pipeline in Kentucky. Capacity could be increased to 400,000 barrels per day to meet market demand, primarily by adding additional liquids pumping capacity. From the interconnect with Texas Gas to Louisiana, a portion of the Texas Gas pipeline (“Texas Gas Loop Line”) would be converted from natural gas service to NGLs service. The proposed project would also include constructing a new large-scale fractionation plant, expanding NGLs storage facilities in Louisiana, constructing a new pipeline connecting these facilities to the converted Texas Gas Loop Line and constructing a new export LPG terminal and related facilities on the Gulf Coast to provide customers access to international markets.

Boardwalk Pipeline and Williams are engaged in comprehensive project development activities including project design, cost estimating, economic and risk analysis, permitting, other legal and regulatory approvals and right-of-way acquisition. Boardwalk Pipeline and Williams are also continuing ongoing discussions with potential customers regarding commitments for pipeline, fractionation, storage and export services to support this project. As of December 31, 2013, Boardwalk Pipeline and BPHC have contributed a total of $79 million to the project for pre-construction development costs.

 

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Approval and completion of this project is subject to, among other conditions, execution of customer contracts sufficient to support the project, acquisition of right-of-way along the pipeline route, and the parties’ receipt of all necessary approvals, including board approvals and regulatory approvals, such as antitrust clearance under the Hart-Scott-Rodino Antitrust Improvements Act and approvals by the FERC, among others. Before the Texas Gas Loop Line can be converted to NGLs service, abandonment authority must be received from FERC. The abandonment application was filed with FERC in May of 2013 and Boardwalk Pipeline estimates the abandonment process will take at least twelve months. In addition, each of the parties has the right, under certain circumstances, to withdraw from the project or from portions of the project, in which case the project may be terminated, only portions of the project may be completed, or the parties respective ownership interests in the project may change. Boardwalk Pipeline and Williams are continuing to evaluate all aspects of the project, including the anticipated date the project would be placed in service if it is completed.

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.

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, basis spreads and time period price spreads 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 2013, 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

 

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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”) through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) 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 PHMSA 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 high risk areas along their pipelines and take additional measures to protect pipeline segments located in highly populated areas. The NGPSA and HLPSA were most recently amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Act”) in 2012, with the 2011 Act requiring increased maximum civil penalties for certain violations to $200,000 per violation per day, and an increased total cap of $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 more stringent safety controls or 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 laws and 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, discharges 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.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of Boardwalk Pipeline’s operations. While Boardwalk Pipeline believes that they are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect them, there is no assurance that the current regulatory standards will not become more onerous in the future, resulting in more significant costs to maintain compliance or increased exposure to significant liabilities.

Properties:   Boardwalk Pipeline is headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. Boardwalk Pipeline also leases approximately 60,000 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 1.7%, 2.0% and 2.5% of our consolidated total revenue for the years ended December 31, 2013, 2012 and 2011.

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 approximately 6,000 producing wells. In addition, HighMount has working interests in undeveloped oil and gas properties located on approximately 67,000 net acres in Oklahoma which contain primarily oil reserves.

 

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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 3,200 miles of gathering lines and operates over 58,000 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.

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, 2013, HighMount owned 719.3 Bcfe of net proved reserves, of which 92.7% were classified as proved developed reserves. HighMount’s estimated total proved reserves consist of 514.5 Bcf of natural gas, 30.7 MMBbls of NGLs, and 3.4 MMBbls of oil and condensate. HighMount produced approximately 133 MMcfe per day of net natural gas, NGLs and oil during 2013. 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 60 wells during 2013, of which 57 (or 95.0%) are productive wells.

 

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Recent Developments:   The growth in recent years in the production of natural gas and natural gas liquids from new supply areas across the United States, some of which are closer to traditional high value end markets and are less expensive to produce than HighMount’s production, continues to depress the prices of those commodities. This trend is expected to continue for the foreseeable future as production from basins such as the Marcellus Shale and Utica Shale is forecasted to increase significantly over the next several years. As a result of these prevailing low commodity prices, it is not currently economical for HighMount to drill new natural gas wells in the Sonora field. In 2012, HighMount ceased drilling new gas wells and is now solely pursuing a strategy of seeking to develop resource plays expected to be rich in oil, which has not experienced the dramatic price declines of natural gas and natural gas liquids.

In 2011, HighMount acquired acreage in Oklahoma with non-proven oil resources in the Mississippian Lime and Woodford Shale formations. More recently, HighMount has been seeking to develop oil reserves in the Wolfcamp zone of its Sonora acreage. HighMount has drilled a number of exploratory wells in these plays using various horizontal drilling, fracturing and well completion techniques, which are far more expensive to drill than its traditional vertical natural gas wells in the Sonora field. HighMount is not currently drilling new wells on its Oklahoma properties and has one drilling rig working in the Wolfcamp area. To date, these exploratory wells have not yielded sufficient quantities of oil to support commercial development of these properties. Further study and refinement of drilling techniques will be required in order to determine whether there is an economic development opportunity.

In light of these developments, HighMount recorded a goodwill impairment charge of $584 million ($382 million after tax) in 2013. See the Results of Operations by Business Segment section of this MD&A and Note 8 of the Notes to Consolidated Financial Statements included under Item 8 for additional information.

Reserves:   HighMount’s reserves represent its share of reserves based on its net revenue interest in each property. Estimated reserves as of December 31, 2013 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.

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’s lead evaluator has over seven 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 and has held leadership roles in the Society of Petroleum Engineers.

HighMount’s reserves estimates for 2013 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 over 30 years of industry experience and has been practicing consulting petroleum engineering at NSAI since 1989.

 

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The following table sets forth HighMount’s proved reserves at December 31, 2013, based on average 2013 prices of $3.67 per MMBtu for natural gas, $35.39 per Bbl for NGLs and $96.94 per Bbl for oil. Approximately 99% of HighMount’s proved reserves are located in the Permian Basin in Texas and approximately 1% of proved reserves are located in Oklahoma.

 

                         Natural Gas   
       Natural Gas           NGLs                    Oil                    Equivalents   
     (MMcf)    (Bbls)    (Bbls)         (MMcfe)   

 

    

 

 

 

Proved developed

   484,922    27,571,435    2,761,873        666,922      

Proved undeveloped

     29,574      3,143,804       654,870        52,366      

 

    

 

 

 

Total proved

   514,496    30,715,239    3,416,743        719,288      

 

    

 

 

 

HighMount reviews its proved reserves during the fourth quarter of each year. During 2013, HighMount produced 48 Bcfe and recorded negative net reserve revisions of 79 Bcfe due to a reclassification of proved undeveloped reserves to the non-proved category due to variability in well performance primarily in the Mississippian Lime and reduction in drilling plans, driven by continued low natural gas and NGL prices. Estimated net quantities of proved natural gas and oil reserves at December 31, 2013, 2012 and 2011 and changes in the reserves during 2013, 2012 and 2011 are shown in Note 15 of the Notes to Consolidated Financial Statements included under Item 8.

HighMount’s Sonora natural gas-producing properties typically have relatively long reserve lives and high well completion success rates. Based on December 31, 2013 proved reserves and HighMount’s average production from these properties during 2013, the average reserve-to-production index of HighMount’s proved reserves is 15 years.

In order to replenish reserves as they are depleted by production, and to increase reserves, and if determined to be economical, 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 may seek to acquire additional acreage in its core areas of operation, as well as other locations where its management has identified an opportunity. As noted above, HighMount is not currently drilling new natural gas wells and is pursuing a limited drilling program seeking to develop additional oil reserves.

During 2013, 2012 and 2011, HighMount engaged in the drilling activity presented in the following table:

 

Year Ended December 31      2013            2012            2011      

 

 
       Gross            Net               Gross            Net               Gross            Net         

 

 

Development Wells

                                       

Productive Wells

       57              45.3             83              78.5             46              46.0       

Dry Wells

                   3.0                         8.0                         5.0       

 

 

Total Development Wells

       60              48.3             91              86.5             51              51.0       

 

 

Exploratory Wells

                                       

Productive Wells

                                   10              9.5       

Dry Wells

                                               2.0       

 

 

Total Exploratory Wells

                                   12              11.5       

 

 

Total Completed Wells

       60              48.3             91              86.5             63              62.5       

 

 

In addition, at December 31, 2013, HighMount had 14 (13.8 net) wells in progress.

As of December 31, 2013, HighMount had working interests in approximately 6,000 gross producing wells (approximately 5,700 net producing wells) located primarily in the Permian Basin. In addition, HighMount had royalty interests in approximately 249 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.

 

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Acreage:  As of December 31, 2013, HighMount owned interests in 1,055,799 gross (657,354 net) acres in the United States which is comprised of 615,282 gross (474,947 net) developed acres, and 440,517 gross (182,407 net) undeveloped acres.

Leases covering 18,956, 45,804 and 8,150 of HighMount’s net acreage will expire during the years ended December 31, 2014, 2015 and 2016, 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.

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.

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.

 

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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 GHG report in March of 2013 for the 2012 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 18 primarily upper, upscale hotels. Each hotel in the chain is managed by Loews Hotels. Seven of these hotels are owned by Loews Hotels, seven 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 2.5%, 2.7% and 2.4% of our consolidated total revenue for the years ended December 31, 2013, 2012 and 2011. The hotels are described below.

 

Name and Location    Number of 
Rooms 
 

 

 

Owned (a):

  

Loews Annapolis Hotel, Annapolis, Maryland

     220          

Loews Coronado Bay, San Diego, California (b)

     440          

Loews Miami Beach Hotel, Miami Beach, Florida

     790          

Loews Philadelphia Hotel, Philadelphia, Pennsylvania

     585          

Loews Regency Hotel, New York, New York (c)

     379          

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 Boston Hotel, Boston, Massachusetts

     225          

Loews Hollywood Hotel, Hollywood, California

     632          

Loews Madison Hotel, Washington, D.C.

     356          

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          

 

(a)

In February of 2014, the Loews LeConcorde Hotel in Quebec City, Canada was closed.

(b)

The hotel has a land lease expiring in 2034.

(c)

The hotel has a land lease expiring in 2036 with a renewal option for 24 years.

Under Construction: In 2013, Loews Hotels is a 50% partner in a joint venture which is constructing Cabana Bay Beach Resort, an 1,800 guestroom hotel at Universal Orlando, Florida. The first phase is expected to open early in 2014. Construction continues on the Loews Chicago Hotel, a 400 guestroom hotel which Loews Hotels agreed to purchase, upon completion of development expected to occur early in 2015.

 

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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.

EMPLOYEE RELATIONS

Including our operating subsidiaries as described below, we employed approximately 18,175 persons at December 31, 2013. We, and our subsidiaries, have experienced satisfactory labor relations.

CNA employed approximately 7,035 persons.

Diamond Offshore employed approximately 5,500 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 3,780 persons, approximately 1,100 of whom are union members covered under collective bargaining units.

EXECUTIVE OFFICERS OF THE REGISTRANT

 

                 First  
                 Became  
                 Name    Position and Offices Held    Age      Officer  

 

David B. Edelson

  

Senior Vice President

   54      2005  

Gary W. Garson

  

Senior Vice President, General Counsel and Secretary

   67      1988  

Peter W. Keegan

  

Senior Vice President and Chief Financial Officer

   69      1997  

Richard W. Scott

  

Senior Vice President and Chief Investment Officer

   60      2009  

Kenneth I. Siegel

  

Senior Vice President

   56      2009  

Andrew H. Tisch

  

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

   64      1985  

James S. Tisch

  

Office of the President, President and Chief Executive Officer

   61      1981  

Jonathan M. Tisch

  

Office of the President and Co-Chairman of the Board

   60      1987  

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 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.

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

 

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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 which would result in a charge to CNA’s earnings.

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. 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 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 difficult to predict. Examples of emerging or potential claims and coverage issues include:

 

   

uncertainty in future medical costs in workers’ compensation. In particular, medical cost inflation could be greater than expected due to new treatments, drugs and devices; increased health care utilization; and/or the future costs of health care facilities. In addition, the relationship between workers’ compensation and

 

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government and private health care providers could change, potentially shifting costs to workers’ compensation;

 

   

increased uncertainty related to medical professional liability, medical products liability and workers’ compensation coverages resulting from the Patient Protection and Affordable Care Act;

 

   

significant class action litigation; and

 

   

mass tort claims, including bodily injury claims related to 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 are based on key assumptions including morbidity, mortality, policy persistency (the percentage of policies remaining in force) and discount rate. These assumptions are critical bases for reserve estimates and, while monitored consistently, are inherently uncertain due to the limited historical data and industry data available to CNA, as only a small portion of the long term care policies which have been written to date are in claims paying status, and the potential changing trends in morbidity and mortality over time. Assumptions relating to mortality and discount rate also form the basis for reserve determination for payout annuity products.

A prolonged period during which interest rates remain at levels lower than those anticipated in CNA’s reserving would result in shortfalls in investment income on assets supporting CNA’s obligations under long term care policies and payout annuity contracts, which may also require changes to its reserves. This risk is more significant for long term care products because the long potential duration of the policy obligations exceeds the duration of the supporting investment assets. If estimated reserves are insufficient for any reason, including changes in assumptions, 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, floods, riots, strikes, civil commotion 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 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. Additionally, the U.S. government currently provides financial protection through the Terrorism Risk Insurance Program Reauthorization

 

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Act, which is set to expire December 31, 2014. Should that act expire without reauthorization or be reauthorized under materially different terms, CNA’s net exposure to a significant terrorist event could increase.

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 the amounts CNA collects from reinsurers are less than the amount recorded 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.

CNA may incur significant realized and unrealized investment losses and volatility in net investment income arising from changes in the financial markets.

CNA’s investment portfolio is exposed to various risks, such as interest rate, credit, equity and currency risks, many of which are unpredictable. Financial markets are highly sensitive to changes in economic conditions, monetary policies, domestic and international geopolitical issues and many other factors. Changes in financial

 

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markets including fluctuations in interest rates, credit, equity and currency prices, and many other factors beyond CNA’s control can adversely affect the value of its investments and the realization of investment income.

CNA has significant holdings in fixed maturity investments that are sensitive to changes in interest rates. A decline in interest rates may reduce the returns earned on new fixed maturity investments, thereby reducing CNA’s net investment income, while an increase in interest rates may reduce the value of its existing fixed maturity investments. The value of CNA’s fixed maturity investments is also subject to risk that certain investments may default or become impaired due to deterioration in the financial condition of issuers of the investments CNA holds. Any such impairments which CNA deems to be other-than-temporary would result in a charge to its earnings.

In addition, CNA invests a portion of its assets in equity securities and limited partnerships which are subject to greater market volatility than its fixed maturity investments. Limited partnership investments generally provide a lower level of liquidity than fixed maturity or equity investments and therefore may also limit CNA’s ability to withdraw assets. As a result of all of these factors, CNA may not earn an adequate return on its investments, may incur losses on the disposition 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. 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 intercompany 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. 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.

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. In addition, the level of offshore drilling activity may be adversely affected if operators reduce or defer new investment in offshore projects or reallocate their drilling budgets away from offshore drilling in favor of shale plays or other land-based energy markets, which could reduce demand for Diamond Offshore’s rigs and newbuilds. 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;

 

   

civil unrest;

 

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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;

 

   

laws and regulations relating to environmental or energy security matters, including those addressing the risks of global climate change;

 

   

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 suppliers or subcontractors to perform or supply goods or services or personnel shortages.

Diamond Offshore’s drilling contracts with its customers provide for varying levels of indemnity and allocation of liabilities between its customers and Diamond Offshore with respect to the hazards and risks inherent in, and damages or losses arising out of, its operations, and Diamond Offshore may not be fully protected. Diamond Offshore’s contracts with its customers generally provide that Diamond Offshore and its customers each assume liability for their respective personnel and property. Diamond Offshore’s contracts also generally provide that its customers assume most of the responsibility for and indemnify Diamond Offshore against loss, damage or other liability resulting from, among other hazards and risks, pollution originating from the well and subsurface damage or loss, while Diamond Offshore typically retains responsibility for and indemnifies its customers against pollution originating from the rig. However, in certain drilling contracts Diamond Offshore may not be fully indemnified by its customers for damage to their property and/or the property of their other contractors. In certain contracts Diamond Offshore may assume liability for losses or damages (including punitive damages) resulting from pollution or contamination caused by negligent or willful acts of commission or omission by Diamond Offshore, its suppliers and/or subcontractors, generally subject to negotiated caps on a per occurrence basis and/or on an aggregate basis for the term of the contract. In some cases, suppliers or subcontractors who provide equipment or services to

 

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Diamond Offshore may seek to limit their liability resulting from pollution or contamination. Diamond Offshore’s contracts are individually negotiated, and the levels of indemnity and allocation of liabilities in them can vary from contract to contract depending on market conditions, particular customer requirements and other factors existing at the time a contract is negotiated.

Additionally, the enforceability of indemnification provisions in Diamond Offshore’s contracts may be limited or prohibited by applicable law or may not be enforced by courts having jurisdiction, and Diamond Offshore could be held liable for substantial losses or damages and for fines and penalties imposed by regulatory authorities. The indemnification provisions of Diamond Offshore’s contracts may be subject to differing interpretations, and the laws or courts of certain jurisdictions may enforce such provisions while other laws or courts may find them to be unenforceable, void or limited by public policy considerations, including when the cause of the underlying loss or damage is Diamond Offshore’s gross negligence or willful misconduct, when punitive damages are attributable to Diamond Offshore or when fines or penalties are imposed directly against Diamond Offshore. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is unsettled under certain laws that are applicable to Diamond Offshore’s contracts. Current or future litigation in particular jurisdictions, whether or not Diamond Offshore is a party, may impact the interpretation and enforceability of indemnification provisions in its contracts. There can be no assurance that Diamond Offshore’s contracts with its customers, suppliers and subcontractors will fully protect it against all hazards and risks inherent in its operations. There can also be no assurance that those parties with contractual obligations to indemnify Diamond Offshore will be financially able to do so or will otherwise honor their contractual 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.

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 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 lower demand or excess rig supply intensify the competition in the industry and often result in periods of low utilization. During these periods, Diamond Offshore’s existing rigs and newbuilds may not obtain contracts for future work and may be idle for long periods of time or may be able to obtain work only under contracts with lower dayrates or less favorable terms. Additionally, 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.

 

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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 100 floaters on order and scheduled for delivery between 2014 and 2016, with approximately 32% of these rigs scheduled for delivery in 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 34% of Diamond Offshore’s consolidated revenues in 2013 and, as of February 5, 2014, accounted for approximately $1.0 billion and $500 million of contract drilling backlog in 2014 and in the aggregate for the years 2015 and 2016 and to which 10 of Diamond Offshore’s floaters are currently contracted, has announced plans to construct locally 28 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, both Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract as well as its newbuilds coming to market and could materially adversely affect Diamond Offshore’s utilization rates, particularly in Brazil.

Diamond Offshore may not be able to renew or replace expiring contracts for its existing rigs or obtain contracts for its uncontracted newbuilds.

Diamond Offshore has a number of customer contracts that will expire in 2014 and 2015. Additionally, certain of its newbuilds that are expected to come to market during 2014 are contracted on a short term basis or are currently uncontracted. Although Diamond Offshore will seek to secure contracts for these units before construction is completed, its ability to renew or replace expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of its customers. Given the highly competitive and historically cyclical nature of the industry, Diamond Offshore may be required to renew or replace expiring contracts or obtain new contracts at dayrates that are below, and potentially substantially below, existing dayrates, or may be unable to secure contracts for these units.

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

As of February 5, 2014, Diamond Offshore’s contract drilling backlog was approximately $6.8 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 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 2013, Diamond Offshore’s five largest customers in the aggregate accounted for 54% of its consolidated revenues. Diamond Offshore expects Petrobras, which accounted for approximately 34% of Diamond Offshore’s consolidated revenues in 2013, to continue to be a significant customer in 2014. Diamond Offshore’s contract drilling backlog, as of February 5, 2014, includes $1.0 billion, or 36%, in 2014 and $500 million in aggregate for the years 2015 and 2016, which is attributable to contracts with Petrobras for operations offshore Brazil. Petrobras has announced plans to construct locally, 28 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

 

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materially adversely affect utilization rates, particularly in Brazil. In addition, if Petrobras or another significant customer experiences liquidity constraints or other financial difficulties, it could materially adversely affect Diamond Offshore’s utilization rates in Brazil or other markets and also displace demand for its other drilling rigs and newbuilds as the resulting excess supply enters the market. 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 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, while customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. Diamond Offshore may be exposed to decreasing dayrates if any of its rigs are working under short term contracts during a declining market. Likewise, if any of its rigs are committed under long term contracts during an improving market, Diamond Offshore may be unable to enjoy the benefit of rising dayrates for the duration of those contracts. Exposure to falling dayrates in a declining market or the inability 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. In addition, equipment repair and maintenance expenses fluctuate depending on the type of activity the rig is performing, the age and condition of the equipment and general market factors impacting relevant parts, components and services. 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 some cases, because of depressed market conditions, restricted credit markets, economic downturns or other factors beyond Diamond Offshore’s control, its customers may repudiate or otherwise fail to perform their obligations under Diamond Offshore’s contracts with them. Any recovery Diamond Offshore might obtain in these cases may not fully compensate it for the loss of the contract. In any case, the early termination of a contract may result in a rig being idle for an extended period of time, which could have a material adverse effect on Diamond Offshore’s financial condition, results of operations and cash flows. If Diamond Offshore’s customers cancel some of their contracts or if Diamond Offshore elects to terminate in the event that a customer fails to perform, and are 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 Diamond Offshore’s contracts are renegotiated, it could materially and adversely affect Diamond Offshore’s financial condition, results of operations and cash flows.

 

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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, riot, civil disturbances and acts of terrorism;

 

   

piracy or assaults on property or personnel;

 

   

kidnapping of personnel;

 

   

seizure, expropriation, nationalization, deprivation, malicious damage, or other loss of possession or use of property or equipment;

 

   

renegotiation or nullification of existing contracts;

 

   

disputes and legal proceedings in international jurisdictions;

 

   

changing social, political and economic conditions;

 

   

imposition of wage and price controls, 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 and confiscatory or discriminatory taxation.

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;

 

   

local content requirements;

 

   

taxation of offshore earnings and earnings of expatriate personnel; and

 

   

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

 

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

 

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Rig conversions, upgrades or newbuilds 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 three ultra-deepwater drillships and its harsh environment, ultra-deepwater semisubmersible rig under construction and its construction of the Ocean Apex. 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 or change orders;

 

   

weather interferences or storm damage;

 

   

difficulties in obtaining necessary permits or in meeting permit conditions;

 

   

design and engineering problems;

 

   

disputes with shipyards or suppliers;

 

   

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 relies on third-party suppliers, manufacturers and service providers to secure equipment, components and parts used in rig operations, conversions, upgrades and construction.

Diamond Offshore’s reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes it to volatility in the quality, price and availability of such items. Certain components, parts and equipment that are used in Diamond Offshore’s operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond Diamond Offshore’s control and could materially disrupt its operations or result in the delay, renegotiation or cancellation of a drilling contract, thereby causing a loss of contract drilling backlog and/or revenue as well as an increase in operating costs.

 

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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 have sufficient available cash to continue making distributions to unitholders at the current distribution rate or at all.

The amount of cash Boardwalk Pipeline has available to 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:

 

   

fluctuations in cash generated by its operations, including as a result of the seasonality of its business, customer payment issues, general business conditions and market conditions, which impact, for example, contract renewals, basis spreads, time period price spreads, market rates, and supply and demand for natural gas and its services;

 

   

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

 

   

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 on acceptable terms to fund operations or capital expenditures, including acquisitions; restrictions contained in its debt agreements; and

 

   

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

There is no guarantee that unitholders will receive quarterly distributions from Boardwalk Pipeline. Boardwalk Pipeline’s distributions are determined each quarter by its board of directors based on the board’s consideration of its financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. In February of 2014, Boardwalk Pipeline declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that Boardwalk Pipeline has declared and paid in recent periods. Boardwalk Pipeline may 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, debt repayment or other business needs.

Boardwalk Pipeline may not be able to replace expiring gas transportation and storage contracts at attractive rates or on a long term basis and may not be able to sell short term services at attractive rates or at all due to narrower basis differentials which adversely affect the value of its transportation services and narrowing of price spreads between time periods and reduced volatility which adversely affect Boardwalk Pipeline’s storage services.

New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and Utica shale plays which are closer to the traditional high value markets Boardwalk Pipeline serves than the supply basins connected to its facilities. As a result, pipeline infrastructure has been and continues to be developed to move gas and NGLs from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to Boardwalk Pipeline’s pipelines and have caused some of

 

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the gas production that is supplied to Boardwalk Pipeline’s system to be diverted to other market areas. These factors have adversely affected, and are expected to continue to adversely affect, the value of Boardwalk Pipeline’s transportation and storage services and have lowered the volumes Boardwalk Pipeline has transported on its pipelines, as further discussed below.

Transportation Services:

A key market driver that influences the rates and terms of Boardwalk Pipeline’s transportation contracts is the current and anticipated basis differentials - generally meaning the difference in the price of natural gas at receipt and delivery points on Boardwalk Pipeline’s natural gas pipelines - which influence how much 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, the proximity of supply areas to end use markets, 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 Boardwalk Pipeline’s pipeline systems. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on Boardwalk Pipeline’s pipeline systems have narrowed significantly in recent years, reducing the transportation rates and other contract terms Boardwalk Pipeline can negotiate with its customers for available transportation capacity and for contracts due for renewal for its firm transportation services. The narrowing of basis differentials has also adversely affected the rates Boardwalk Pipeline is able to charge for its interruptible and short term firm transportation services.

Each year, a portion of Boardwalk Pipeline’s firm natural gas transportation contracts expire and need to be renewed or replaced. For the reasons discussed above and elsewhere in this Report, in recent periods Boardwalk Pipeline has renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially adversely impacted its transportation revenues. Boardwalk Pipeline expects this trend to continue and therefore may not be able to sell its available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, which would continue to adversely affect its business.

In 2008 and 2009, Boardwalk Pipeline placed into service a number of large new pipelines and expansions of its system, including its East Texas Pipeline, Southeast Expansion, Gulf Crossing Pipeline and Fayetteville and Greenville Laterals. These projects were supported by firm transportation agreements with anchor shippers, typically having a term of ten years and pricing and other terms negotiated based on then current market conditions, which included wider basis spreads and, correspondingly, higher transportation rates than those prevailing in the current market. As a result, in 2018 and 2019, Boardwalk Pipeline will have significantly more contract expirations than other years. Boardwalk Pipeline cannot predict what market conditions will prevail at the time such contracts expire and what pricing and other terms may be available in the marketplace for renewal or replacement of such contracts. If Boardwalk Pipeline is unable to renew or replace these and other expiring contracts when they expire, or if the terms of any such renewal or replacement contracts are not as favorable as the expiring agreements, Boardwalk Pipeline’s revenues and cash flows could be materially adversely affected.

Storage and PAL Services:

Boardwalk Pipeline owns and operates substantial natural gas storage facilities. The market for the storage and PAL services that it offers is also impacted by the factors discussed above, as well as natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. Recently, the market conditions described above have caused time period price spreads to narrow considerably and price volatility of natural gas to decline significantly, reducing the rates Boardwalk Pipeline can charge for its storage and PAL services and adversely impacting the value of these services. These market conditions together with regulatory changes in the financial services industry have also caused a number of gas marketers, which have traditionally been large consumers of Boardwalk Pipeline’s storage and PAL services, to exit the market, further impacting the market for those services.

Boardwalk Pipeline expects the conditions described above to continue in 2014 and cannot give assurances they will not continue beyond 2014. These market factors and conditions adversely impact revenues, earnings and distributable cash flow, and could impact Boardwalk Pipeline on a long term basis.

 

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Boardwalk Pipeline may not be successful in executing its strategy to grow and diversify its business.

Boardwalk Pipeline relies primarily on the revenues generated from its long-haul natural gas transportation and storage services. As a result, negative developments in these services have significantly greater impact on its financial condition and results of operations than if Boardwalk Pipeline maintained more diverse assets. Boardwalk Pipeline is pursuing a strategy of growing and diversifying its business through acquisition and development of assets in complementary areas of the midstream energy sector, such as liquids transportation and storage assets, among others. Boardwalk Pipeline may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable.

In pursuing its growth and diversification strategy, Boardwalk Pipeline has been pursuing development (together with a joint venture partner) of a large capital project, the Bluegrass Project, consisting of a pipeline that would deliver NGLs from the Marcellus and Utica shale production areas of Pennsylvania, Ohio and West Virginia to end use markets in the Gulf Coast area, and constructing new fractionation, liquids storage and export facilities located in the Gulf Coast region. Boardwalk Pipeline continues to have ongoing discussions with potential customers regarding commitments that would support constructing this project and has not made any external commitments to proceed with the project. Boardwalk Pipeline may incur substantial costs in developing this or other projects or otherwise pursuing growth and diversification opportunities; however, Boardwalk Pipeline can give no assurance that any such project will be completed, in whole or in part, or, if completed, that any such project or acquisition will be on attractive terms or generate a positive return.

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

The prices of natural gas and NGLs fluctuate 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.

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 which could adversely impact revenues, earnings and distributable cash flow.

 

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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.

Changes in the pipeline safety laws and regulations requiring substantial changes to existing integrity management programs or 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 PHMSA of 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, 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 stringent 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 in 2014 or soon thereafter. 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.

Further, 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.

Boardwalk Pipeline’s natural gas transportation and storage operations are subject to extensive regulation by FERC, including rules and regulations related to the rates it can charge for its services and its ability to construct or abandon facilities. FERC’s rate-making policies could limit its ability to recover the full cost of operating its pipelines, including earning a reasonable return.

Boardwalk Pipeline’s natural gas transportation and storage operations are subject to extensive regulation by FERC, including the types and terms of services it may offer to customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. FERC action in any of these areas could adversely affect Boardwalk Pipeline’s ability to compete for business, construct new facilities, offer new services or recover the full cost of operating its pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to FERC’s regulations. FERC can also deny Boardwalk Pipeline the right to remove certain facilities from service.

FERC also regulates the rates Boardwalk Pipeline 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.

 

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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’s pipelines under FERC jurisdiction were to file a rate case, or if they have to defend their rates in a proceeding commenced by 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.

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

Boardwalk Pipeline’s growth depends on its ability to grow and diversify its business by among other things, investing in assets through acquisitions or joint ventures 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 project 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;

 

   

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 or delays of regulatory approvals.

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.

 

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There is no certainty that Boardwalk Pipeline will be able to complete these acquisitions or projects on schedule, on budget or at all.

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 11% of its 2013 revenues. Boardwalk Pipeline’s top ten customers comprised approximately 46% of its revenues in 2013. 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.

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

HighMount may not be able to replace reserves and sustain production. 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. HighMount’s investment opportunities have shifted since 2011 from drilling vertical gas wells to produce gas reserves to more expensive exploratory horizontal wells testing and evaluating non-proven oil resources. The shift from drilling predictable vertical gas wells in mature fields to drilling exploratory horizontal oil wells creates greater uncertainty regarding HighMount’s ability to replenish or grow its reserves. Unless HighMount replaces its reserves that are depleted by production, negative reserve revisions, or otherwise, through successful development, exploration or acquisition, its proved reserves, and therefore its asset base, will decline over time. HighMount may not be able to successfully find and produce reserves economically in the future or acquire proved reserves at acceptable costs. HighMount makes a substantial amount of capital expenditures for the acquisition, exploration and development of reserves and some of those efforts have not, and may in the future not, lead to the successful development of additional reserves, which could result in additional impairment charges, as discussed below, which could be material. HighMount’s net cash flows have been negatively impacted by reduced natural gas and NGL prices as well as increased drilling costs of 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.

 

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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.

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 further write-down the carrying value of its natural gas and oil properties or to impair its other assets, such as its pipeline assets. 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 additional unsuccessful 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 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 ceiling test impairment charges of $291 million and $680 million ($186 million and $433 million after tax) for the years ended December 31, 2013 and 2012. The 2013 write-downs were primarily attributable to negative reserve revisions due to variability in well performance where HighMount is testing different horizontal target zones and hydraulic fracture designs and due to reduced average NGL prices used in the ceiling test calculations. The 2012 write-downs were the 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

 

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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 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 and third party claimants rather than its investors. Each jurisdiction in which CNA does business has established supervisory agencies that regulate its business, generally at the state level. Any changes in federal regulation could also impose significant burdens on CNA. 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;

 

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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, increase rates 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.

In the aftermath of the 2010 Macondo well blowout 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 PHMSA of 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.

 

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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 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 resulting from a spill or other release, 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

 

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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.

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 and storage assets 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

 

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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.

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:

 

             2013                      2012          
  

 

 

 
       High      Low      High      Low  

 

 

First Quarter

       $       44.78       $       41.06       $       40.16       $       37.02       

Second Quarter

     47.10         42.59         41.80         38.14       

Third Quarter

     47.94         44.03         42.86         39.04       

Fourth Quarter

     49.43         46.10         43.36         39.57       

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, 2013. 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, 2008 and that all dividends were reinvested.

 

 

LOGO

 

      2008      2009      2010      2011      2012      2013  

Loews Common Stock

     100.00         129.84         139.97         136.28         148.43         176.69   

S&P 500 Index

     100.00         126.46         145.51         148.59         172.37         228.19   

Loews Peer Group (a)

     100.00         128.27         142.73         150.43         170.78         218.59   

 

(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 2013 and 2012.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides certain information as of December 31, 2013 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)

    6,476,391                $ 38.50              6,838,923           

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 1,090 holders of record of our common stock.

Common Stock Repurchases

We repurchased our common stock in 2013 as follows:

 

Period   Total number of
shares purchased
  Average price 
paid per share 

January 1, 2013 – March 31, 2013

      2,094,900           $43.70      

April 1, 2013 – June 30, 2013

      1,931,700           44.06      

July 1, 2013 – September 30, 2013

      918,200           45.49      

October 1, 2013 – December 31, 2013

      0           N/A      

 

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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    2013      2012      2011      2010      2009  

 

 
(In millions, except per share data)                                   

Results of Operations:

              

Revenues

   $ 15,053        $ 14,552        $ 14,129        $ 14,615        $ 14,117     

Income before income tax

   $ 1,429        $ 1,399        $ 2,226        $ 2,902        $ 1,728     

Income from continuing operations

   $ 1,069        $ 1,110        $ 1,694        $ 2,008        $ 1,384     

Discontinued operations, net

              (20)         (2)    

 

 

Net income

     1,069          1,110          1,694          1,988          1,382     

Amounts attributable to noncontrolling interests

     (474)         (542)         (632)         (699)         (819)    

 

 

Net income attributable to Loews Corporation

   $ 595        $ 568        $ 1,062        $ 1,289        $ 563     

 

 

Net income attributable to Loews Corporation:

              

Income from continuing operations

   $ 595        $ 568        $ 1,062        $ 1,308        $ 565     

Discontinued operations, net

              (19)         (2)    

 

 

Net income

   $ 595        $ 568        $ 1,062        $ 1,289        $ 563     

 

 

Diluted Net Income Per Share:

              

Income from continuing operations

   $ 1.53        $ 1.43        $ 2.62        $ 3.11        $ 1.31     

Discontinued operations, net

              (0.04)         (0.01)    

 

 

Net income

   $ 1.53        $ 1.43        $ 2.62        $ 3.07        $ 1.30     

 

 

Financial Position:

              

Investments

   $    52,973        $    53,048        $    49,028        $    48,907        $    46,034     

Total assets

     79,939          80,021          75,268          76,198          73,990     

Debt

     10,846          9,210          9,001          9,477          9,485     

Shareholders’ equity

     19,458          19,459          18,772          18,386          16,833     

Cash dividends per share

     0.25          0.25          0.25          0.25          0.25     

Book value per share

     50.25          49.67          47.33          44.35          39.60     

Shares outstanding

     387.21          391.81          396.59          414.55          425.07     

 

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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

   51

Parent Company Structure

   52

Critical Accounting Estimates

   52

Results of Operations by Business Segment

   55

CNA Financial

   55

Diamond Offshore

   68

Boardwalk Pipeline

   75

HighMount

   78

Loews Hotels

   82

Corporate and Other

   84

Liquidity and Capital Resources

   85

CNA Financial

   85

Diamond Offshore

   86

Boardwalk Pipeline

   88

HighMount

   89

Loews Hotels

   89

Corporate and Other

   89

Contractual Obligations

   90

Investments

   90

Forward-Looking Statements

   95

 

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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 53% 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 a chain 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, 2013 was $595 million, or $1.53 per share, compared to $568 million, or $1.43 per share, in 2012.

Results for the years ended December 31, 2013 and 2012 include the following significant items (after tax and noncontrolling interests):

 

   

a ceiling test impairment charge at HighMount related to the carrying value of its natural gas and oil properties of $186 million in 2013 and $433 million in 2012;

 

   

goodwill impairment charges of $398 million in 2013 primarily related to HighMount reflecting the continued low market prices for natural gas and natural gas liquids and recent history of negative reserve revisions; and

 

   

a $111 million charge in 2013 related to CNA’s retroactive reinsurance agreement to cede its legacy asbestos and environmental pollution liabilities to National Indemnity, a subsidiary of Berkshire Hathaway, Inc. (“Loss Portfolio Transfer” or “LPT”). Under retroactive reinsurance accounting, amounts ceded through the LPT in excess of the consideration paid result in a deferred gain that is recognized in income over future periods. During the fourth quarter of 2013, the cumulative amounts ceded under the LPT exceeded the consideration paid, resulting in the recognition of an accounting loss.

Income before ceiling test and goodwill impairment charges, the impact of the LPT charge and net investment gains was $1.3 billion in 2013 as compared to $968 million in 2012. This increase is primarily due to higher earnings at CNA and increased investment income at the Parent Company due to improved performance of equities and limited partnership investments. These increases were partially offset by lower earnings at Diamond Offshore.

CNA’s earnings increased primarily from improved non-catastrophe current accident year underwriting results, higher investment income and lower catastrophe losses. These increases were partially offset by a lower level of favorable net prior year development in 2013 as compared to 2012. The prior year catastrophe losses included $171 million (after tax and noncontrolling interests) related to Storm Sandy.

 

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Diamond Offshore’s earnings decreased primarily due to lower utilization including downtime for scheduled surveys and shipyard projects and a $27 million charge (after noncontrolling interests) for an uncertain tax position related to Egyptian operations. In addition, Diamond Offshore’s earnings in 2012 included a gain of $32 million (after tax and noncontrolling interests) from the sale of six jack-up rigs.

Book value per share increased to $50.25 at December 31, 2013 from $49.67 at December 31, 2012. Book value per share excluding Accumulated other comprehensive income (“AOCI”) increased to $49.38 at December 31, 2013 from $47.94 at December 31, 2012.

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 14 of the Notes to Consolidated Financial Statements included under Item 8) and 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 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

 

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conditions. Further information on CNA’s reinsurance receivables is included in Note 17 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 19 of the Notes to Consolidated Financial Statements included under Item 8.

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 1 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 life and group products are based on certain assumptions including morbidity, mortality, policy persistency and discount rates. The adequacy of the reserves is 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.

A prolonged period during which interest rates remain at levels lower than those anticipated in CNA’s reserving discount rate assumption could result in shortfalls in investment income on assets supporting CNA’s obligations under long term care policies and payout annuity contracts, which may also require changes to CNA’s reserves.

These changes to CNA’s reserves could materially adversely impact our results of operations and equity. The reserving process is discussed in further detail in the Reserves – Estimates and Uncertainties section below.

 

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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 16 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 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 years ended December 31, 2013 and 2012, HighMount recognized impairment charges of $291 million and $680 million ($186 million and $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.

 

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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.

A ceiling test impairment charge at HighMount is considered a triggering event that requires a goodwill impairment analysis. This analysis resulted in HighMount recording a goodwill impairment charge of $584 million ($382 million after tax), see the Results of Operations by Business Segment section of this MD&A and Note 8 of the Notes to Consolidated Financial Statements included under Item 8 for additional information.

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 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

On February 10, 2014, CNA entered into a definitive agreement to sell the majority of its run-off annuity and pension deposit business. Further information on the sale is included in Note 23 of the Notes to Consolidated Financial Statements included under Item 8.

 

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Reserves – Estimates and Uncertainties

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. As noted below, CNA reviews its reserves for each segment of its business periodically and any such review could result in the need to increase reserves in amounts which could be material and could adversely impact its results of operations, equity, business and insurer financial strength and corporate debt ratings. Further information on reserves is provided in Note 9 of the Notes to Consolidated Financial Statements included under Item 8.

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 9 of the Notes to Consolidated Financial Statements included under Item 8.

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:

 

   

uncertainty in future medical costs in workers’ compensation. In particular, medical cost inflation could be greater than expected due to new treatments, drugs and devices; increased health care utilization; and/or the future costs of health care facilities. In addition, the relationship between workers’ compensation and government and private health care providers could change, potentially shifting costs to workers’ compensation;

 

   

increased uncertainty related to medical professional liability, medical products liability and workers’ compensation coverages resulting from the Patient Protection and Affordable Care Act;

 

   

significant class action litigation; and

 

   

mass tort claims, including bodily injury claims related to 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.

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.

 

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To mitigate the risks posed by CNA’s exposure to A&EP claims and claim adjustment expenses, as further discussed in Note 9 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 a retroactive reinsurance contract. During 2013 the cumulative amounts ceded under the Loss Portfolio Transfer exceeded the consideration paid, resulting in a $189 million deferred retroactive reinsurance gain. This deferred benefit will be recognized in earnings in future periods in proportion to actual recoveries under the Loss Portfolio Transfer. Over the life of the contract, there is no economic impact as long as any additional losses are within the limit under the contract.

Establishing Property & Casualty 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 reviewed at least once during the year. 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 and management 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.

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.

 

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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 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

 

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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.

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, changes to the tort environment 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.

 

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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 management liability products and Surety products. This includes professional liability coverages provided to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and other professional firms. This 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 these products 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 $550 million. If the estimated claim severity decreases by 3%, CNA estimates that net reserves would decrease by approximately $200 million. CNA’s net reserves for these products were approximately $5.9 billion at December 31, 2013.

Within CNA Commercial, the two types of business for which CNA believes a significant 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 $400 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 by approximately $400 million. Net reserves for CNA Commercial workers’ compensation were approximately $4.6 billion at December 31, 2013.

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 $200 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 $3.7 billion at December 31, 2013.

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

 

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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    2013        2012    

 

 
(In millions)              

Gross Case Reserves

     $      8,374               $ 8,771       

Gross IBNR Reserves

           9,350                 9,824       

 

 

Total Gross Carried Claim and Claim Adjustment Expense Reserves

     $    17,724               $ 18,595       

 

 

Net Case Reserves

     $      7,541               $ 7,811       

Net IBNR Reserves

           8,486                 8,786       

 

 

Total Net Carried Claim and Claim Adjustment Expense Reserves

     $    16,027               $      16,597       

 

 

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    2013        2012    

 

 
(In millions)              

Gross Case Reserves

     $      1,140               $        1,207       

Gross IBNR Reserves

           2,167                 1,955       

 

 

Total Gross Carried Claim and Claim Adjustment Expense Reserves

     $      3,307               $ 3,162       

 

 

Net Case Reserves

     $         283               $ 292       

Net IBNR Reserves

              184                 220       

 

 

Total Net Carried Claim and Claim Adjustment Expense Reserves

     $         467               $ 512       

 

 

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 estimates 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 would be increased to the greater amount. Any such increase would be reflected in CNA’s results of operations in the period in which the need for such adjustment is determined, and could materially adversely affect CNA’s results of operations, equity and business and insurer financial strength and corporate debt ratings.

 

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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 rate 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.

CNA’s current GAAP payout annuity 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 impacts to results of operations in the table below are after consideration of the existing margin.

 

December 31, 2013    Estimated Reduction 
to Pretax Income 
 

 

 
(In millions of dollars)       

Hypothetical revisions

  

Discount rate:

  

50 basis point decline

       $ 106           

100 basis point decline

     247           

Mortality:

  

5% decline

     5           

10% decline

     31           

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

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 rate, morbidity, and persistency, which can be affected by policy lapses and death. There is limited historical data and industry data available to CNA for these reserves, as only a small portion of the long term care policies which have been written to date are in claims paying status and trends in morbidity and mortality change over time. As a result, CNA’s long term care reserves may be subject to material increase if these trends develop adversely to its expectations.

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

 

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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.

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 impacts to results of operations in the table below are after consideration of the existing margin.

 

December 31, 2013    Estimated Reduction  
to Pretax Income  
 

 

 
(In millions of dollars)       

Hypothetical revisions

  

Discount rate:

  

50 basis point decline

     $ 305               

100 basis point decline

     1,041               

Morbidity:

  

5% increase

     188               

10% increase

     724               

Persistency:

  

5% decline in voluntary lapse and mortality

     18               

10% decline in voluntary lapse and mortality

     418               

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 Life & Group Non-Core policyholder reserves:

 

December 31, 2013   Claim and claim
adjustment expenses
    Future
policy benefits
    Policyholders’
funds
    Separate
account business
    Total          

 

 
(In millions)                              

Long term care

   $ 1,889          $ 7,329          $ 9,218         

Payout annuities

    613            1,990            2,603         

Institutional markets

    1            9      $ 57       $ 181            248         

Other

    37            4            41         

 

 

Total

    2,540            9,332        57        181            12,110         

Shadow adjustments (a)

    83            406            489         

Ceded reserves

    435            733        35          1,203         

 

 

Total gross reserves

  $ 3,058          $ 10,471      $ 92      $ 181          $     13,802         

 

 

 

December 31, 2012

                             

 

 

Long term care

  $ 1,683          $ 6,879          $ 8,562         

Payout annuities

    637            2,008            2,645         

Institutional markets

    1            12      $ 100      $ 312            425         

Other

    45            4            49         

 

 

Total

    2,366            8,903        100        312            11,681         

Shadow adjustments (a)

    162            1,812            1,974         

Ceded reserves

    478            760        34          1,272         

 

 

Total gross reserves

  $ 3,006          $     11,475      $     134      $ 312          $      14,927         

 

 

 

(a)

To the extent that unrealized gains on fixed income securities supporting long term care products and payout annuity contracts would result in a premium deficiency if those gains were realized, a related decrease in Deferred acquisition costs and/or increase in Insurance reserves are recorded, net of tax and noncontrolling interests, as a reduction of net unrealized gains through Other comprehensive income (“Shadow Adjustments”). The Shadow Adjustments presented above do not include $342 million and $369 million related to Deferred acquisition costs at December 31, 2013 and 2012.

 

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Results of Operations

The following table summarizes the results of operations for CNA for the years ended December 31, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included under Item 8.

 

Year Ended December 31    2013       2012       2011       

 

 
(In millions)                   

Revenues:

      

Insurance premiums

   $ 7,271          $       6,882        $       6,603          

Net investment income

     2,450        2,282        2,054          

Investment gains (losses)

     27        60        (19)         

Other

     365        323        325          

 

 

Total

         10,113        9,547        8,963          

 

 

Expenses:

      

Insurance claims and policyholders’ benefits

     5,947        5,896        5,489          

Amortization of deferred acquisition costs

     1,362        1,274        1,176          

Other operating expenses

     1,318        1,327        1,234          

Interest

     166        170        185          

 

 

Total

     8,793        8,667        8,084          

 

 

Income before income tax

     1,320        880        879          

Income tax expense

     (378     (247     (244)         

Amounts attributable to noncontrolling interests

     (95     (63     (78)         

 

 

Net income attributable to Loews Corporation

   $ 847          $ 570        $ 557          

 

 

2013 Compared with 2012

Net income increased $277 million in 2013 as compared with 2012. Net investment income increased $168 million, primarily driven by a significant increase in limited partnership results. These increases were partially offset by a decrease of $33 million ($19 million after tax and noncontrolling interests) in investment gains. See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Insurance premiums increased $389 million, including an increase of $241 million related to Hardy, which was acquired in July of 2012. Insurance claims and policyholders’ benefits increased $51 million, primarily due to the impact of a $111 million (after tax and noncontrolling interests) deferred gain under retroactive reinsurance accounting and lower aggregate favorable net prior year development, partially offset by lower catastrophe impacts. Further information on net prior year development for 2013 and 2012 is included in Note 9 of the Notes to Consolidated Financial Statements included under Item 8.

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 aggregate favorable net prior year development. Further information on net prior year development for 2012 and 2011 is included in Note 9 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.

 

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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, 2013, 2012 and 2011.

 

Year Ended December 31, 2013    CNA
Specialty
     CNA
Commercial
     Hardy      Total  

 

 
(In millions, except %)                            

Net written premiums

   $       3,091           $       3,312           $           396           $       6,799           

Net earned premiums

     3,004             3,350             361             6,715           

Net investment income

     657             927             4             1,588           

Net operating income

     635             421             9             1,065           

Net realized investment gains (losses)

     (1)            (8)            1             (8)           

Net income

     634             413             10             1,057           

Ratios:

           

Loss and loss adjustment expense

     56.7%         73.9%         44.8%         64.6%       

Expense

     30.0             34.2             48.6             33.1           

Dividend

     0.2             0.2                0.2           

 

 

Combined

     86.9%         108.3%         93.4%         97.9%       

 

 
Year Ended December 31, 2012                            

 

 

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%        

 

 
Year Ended December 31, 2011                            

 

 

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%        

 

 

 

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2013 Compared with 2012

Net written premiums increased $385 million in 2013 as compared with 2012, including an increase of $279 million related to Hardy. Excluding Hardy, the increase in net written premiums was primarily driven by increased rate, partially offset by previous underwriting actions taken in certain business classes in CNA Commercial. Net earned premiums increased $391 million in 2013 as compared with 2012, including $241 million related to Hardy. Excluding Hardy, the increase in net earned premiums was consistent with increases in net written premiums.

The CNA Specialty average rate increased 6% in 2013 as compared with an increase of 5% in 2012 for the policies that renewed in each period. Retention of 85% and 86% was achieved in each period. The CNA Commercial average rate increased 8% in 2013 as compared with an increase of 7% in 2012 for the policies that renewed in each period. Retention of 74% and 77% was achieved in each period. Hardy’s average rate decreased 2% in 2013 as compared with an increase of 1% for 2012 for the policies that renewed in each period. Retention of 70% and 68% was achieved in each period.

Net operating income increased $383 million in 2013 as compared to 2012, primarily due to improved underwriting results, higher net investment income and a settlement benefit of $28 million (after tax and noncontrolling interests) in 2013 for CNA Commercial. These favorable impacts were partially offset by unfavorable net prior year development in 2013 for CNA Commercial. Catastrophe losses were $100 million (after tax and noncontrolling interests) in 2013 as compared to $243 million (after tax and noncontrolling interests) in 2012.

The combined ratio improved 7.1 points in 2013 as compared to 2012. The loss ratio improved 6.2 points in 2013 as compared to 2012, primarily due to an improved current accident year non-catastrophe loss ratio and decreased catastrophe losses in CNA Commercial and Hardy. The expense ratio improved by 0.9 points, primarily due to a higher net earned premium base in CNA Specialty and Hardy, the impact of lower underwriting expenses in CNA Specialty and decreased expenses including favorable changes in estimates of insurance assessment liabilities in CNA Commercial.

Favorable net prior year development decreased by $84 million, from $239 million in 2012 to $155 million in 2013. Further information on net prior year development is included in Note 9 of the Notes to Consolidated Financial Statements included under Item 8.

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 77% and 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 is included in Note 9 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.

On February 10, 2014, CNA entered into a definitive agreement to sell the majority of its run-off annuity and pension deposit business. Further information on the sale is included in Note 23 of the Notes to Consolidated Financial Statements included under Item 8.

The following table summarizes the results of CNA’s Life & Group Non-Core and Other operations for the years ended December 31, 2013, 2012 and 2011.

 

Year Ended December 31, 2013    Life & Group
Non-Core
     Other      Total  

 

 
(In millions)                     

Net earned premiums

     $      559             $           559          

Net investment income

     830          $             32          862          

Net operating loss

     (52)           (182)         (234)         

Net realized investment gains

     21                    24          

Net loss

     (31)           (179)         (210)         
Year Ended December 31, 2012                     

 

 

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)         

 

 

2013 Compared with 2012

Net loss increased $63 million in 2013 as compared with 2012, primarily driven by the impact of a $111 million (after tax and noncontrolling interests) deferred gain under retroactive reinsurance accounting related to the Loss Portfolio Transfer, as further discussed in Note 9 of the Notes to Consolidated Financial Statements included under Item 8. The results were partially offset by $40 million (after tax and noncontrolling interests) of expenses in 2012 due to unlocking actuarial reserve assumptions on CNA’s payout annuity business and long term care reserve strengthening. In 2013, payout annuity reserves were determined to be adequate, therefore no unlocking of actuarial assumptions was required.

 

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CNA’s long term care business was positively impacted in 2013 by the effect of rate increase actions. The favorable impact of rate increase actions was more than offset by unfavorable morbidity.

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 reflected the 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.

Diamond Offshore

Diamond Offshore’s pretax 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 pretax 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 pretax 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 2014 as a result of increased hiring and training activities as it continues the process of crewing its remaining drillships and semisubmersible rigs under construction. Costs to repair and maintain equipment fluctuate depending upon the type

 

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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.

Pretax 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.

In addition, pretax 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.

During 2014, six of Diamond Offshore’s rigs will require 5-year surveys and another three rigs will complete surveys that commenced in 2013. These nine rigs are expected to be out of service for approximately 380 days in the aggregate. Diamond Offshore also expects to spend an additional approximately 670 days during 2014 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects, including contract preparation work for the Ocean Endeavor (approximately 162 days) and North Sea enhancements for the Ocean Patriot (approximately 165 days). The service-life-extension project for the Ocean Confidence is expected to commence late in the first quarter of 2014, and the rig will be out of service for the balance of the year (approximately 290 days). 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, 2014, 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

The ultra-deepwater market has weakened, with an increasing number of rigs competing for fewer available jobs, resulting in a downward trend in recent contract dayrate fixtures and shorter term contracts executed. The most active ultra-deepwater floater markets remain primarily within the offshore basins of West Africa, Brazil and the Gulf of Mexico. However, there has been limited tendering activity thus far in 2014 and the outlook is uncertain for the remainder of 2014. If this trend continues, ultra-deepwater floaters could experience lower utilization, or idle time, and realize lower margins. Many industry analysts predict that there will be an oversupply of floaters in the ultra-deepwater market by the end of 2014.

 

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The market for deepwater floaters has also weakened and is characterized by intermittent demand, and multiple existing rigs face pockets of idle time throughout 2014 while newbuilds may have challenges securing work. Dayrate fixtures are also moderating in this market and are projected by industry analysts to continue softening in 2014. This market has also seen limited tendering activity in 2014 with an uncertain outlook for the balance of the year.

Strength in the mid-water market also varies significantly by region. In both the U.K. and Norwegian sectors of the North Sea, the mid-water market is showing some signs of weakening, in the form of moderating or decreasing dayrates in part due to an increase in the availability of sublet opportunities being offered for some term contracted rigs. Increasing operator interest in frontier markets across Southeast Asia and South America, including Myanmar, Peru, Nicaragua, Trinidad and Tobago, and Colombia, indicates possible future strengthening in those regions, although opportunities in these areas are not expected to emerge quickly. In the Gulf of Mexico, demand for mid-water rigs is limited, while in Brazil, demand has moderated.

Since 2010, there have been a significant number of orders for newbuild ultra-deepwater and deepwater floaters by established drilling contractors as well as new entrants to the industry. Currently, there are approximately 100 newbuild floater rigs that have been announced, including an estimated 28 rigs potentially to be built on behalf of Petróleo Brasileiro S.A. Excluding these customer-ordered rigs, 31 of the 57 newbuilds scheduled for delivery in 2014 through 2015 are not yet contracted for future work, including two of Diamond Offshore’s four rigs expected to be delivered in 2014 and 2015. The offshore drilling industry has been challenged by the addition of these newbuild rigs, which has increased competition and has resulted in downward pressure on dayrates. The influx of newbuilds into the market, combined with established rigs coming off contract in 2014 and 2015, is expected to continue to weaken the ultra-deepwater and deepwater floater markets.

The offshore drilling industry continues to be challenged by growing regulatory demands and more complex customer specifications, which could disadvantage some lower specification rigs. Additionally, customer focus on completing existing projects, possible reduction or deferral of new investment, reallocation of budgets away from offshore projects and particular customer requirements in certain markets could displace, or reduce demand and result in the migration of some ultra-deepwater rigs to work in deepwater, and likewise, some deepwater rigs to compete against mid-water rigs. Various rigs across all segments could experience lower utilization or idle time and lower specification rigs could be cold stacked or scrapped.

Contract Drilling Backlog

The following table reflects Diamond Offshore’s contract drilling backlog as of February 5, 2014, October 23, 2013 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) and February 1, 2013 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2012). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts) and 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 5,
2014
     October 23,
2013
     February 1,    
2013    
 

 

 
(In millions)                     

Floaters:

        

Ultra-Deepwater (a)

    $     4,111          $     4,306          $      4,422          

Deepwater (b)

     794            862            1,229          

Mid-Water (c)

     1,744            1,997            2,649          

 

 

Total Floaters

     6,649            7,165            8,300          

Jack-ups

     180            188            272          

 

 

Total

    $ 6,829          $ 7,353          $ 8,572          

 

 

 

(a)

As of February 5, 2014, for ultra-deepwater floaters includes (i) $823 million attributable to contracted operations offshore Brazil for the years 2014 and 2015, (ii) $1.8 billion attributable to future work for two newbuild drillships, one of which is under construction, for the years 2014 to 2019 and (iii) $641 million attributable to future work for the ultra-deepwater semisubmersible rig under construction for the years 2016 to 2019.

(b)

As of February 5, 2014, for deepwater floaters includes (i) $308 million attributable to contracted operations offshore Brazil for the years 2014 to 2016 and (ii) $36 million for the years 2014 and 2015 attributable to future work for the Ocean Apex, which is under construction.

(c)

As of February 5, 2014, for mid-water floaters includes $421 million attributable to contracted operations offshore Brazil for the years 2014 and 2015.

The following table reflects the amount of Diamond Offshore’s contract drilling backlog by year as of February 5, 2014:

 

Year Ended December 31    Total      2014      2015      2016      2017 – 2019    

 

 
(In millions)                                   

Floaters:

              

Ultra-Deepwater (a)

   $ 4,111       $ 971       $ 1,198         $ 499         $ 1,443       

Deepwater (b)

     794         516         216         62      

Mid-Water (c)

     1,744         999         471         159         115       

 

 

Total Floaters

     6,649         2,486         1,885         720         1,558       

Jack-ups

     180         110         48         22      

 

 

Total

   $      6,829       $     2,596       $     1,933         $       742         $ 1,558       

 

 

 

(a)

As of February 5, 2014, for ultra-deepwater floaters includes (i) $499 million and $324 million for the years 2014 and 2015, attributable to contracted operations offshore Brazil, (ii) $174 million, $361 million and $362 million for the years 2014 to 2016, and $909 million in the aggregate for the years 2017 to 2019, attributable to future work for two newbuild drillships, one of which is under construction and (iii) $107 million for the year 2016 and $534 million in the aggregate for the years 2017 to 2019 attributable to future work for the ultra-deepwater semisubmersible rig under construction.

(b)

As of February 5, 2014, for deepwater floaters includes (i) $112 million, $134 million and $62 million for the years 2014 to 2016, attributable to contracted operations offshore Brazil and (ii) $29 million and $7 million for the years 2014 and 2015 attributable to future work for the Ocean Apex, which is under construction.

(c)

As of February 5, 2014, for mid-water floaters includes $342 million and $79 million for the years 2014 and 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 5, 2014. 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    2014 (a)       2015 (a)       2016 (a)       2017 – 2019   

 

 

Floaters:

           

Ultra-Deepwater

     87%         62%         26%         19%      

Deepwater

     58%         21%         7%      

Mid-Water

     59%         26%         6%         1%      

Total Floaters

     67%         37%         13%         7%      

Jack-ups

     53%         20%         9%      

 

(a)

As of February 5, 2014, includes approximately 1,570, 270 and 215 currently known, scheduled shipyard days for rig commissioning, contract preparation, surveys and extended maintenance projects, as well as rig mobilization days for 2014, 2015 and 2016.

Dayrate and Utilization Statistics

 

Year Ended December 31    2013        2012        2011      

 

 

Revenue earning days (a)

            

Floaters:

            

Ultra-Deepwater

     2,392             2,475             2,387          

Deepwater

     1,530             1,605             1,718          

Mid-Water

     4,186             4,639             5,254          

Jack-ups (b)

     1,949             1,753             2,218          

Utilization (c)

            

Floaters:

            

Ultra-Deepwater

     82%             85%             82%          

Deepwater

     84%             88%             94%          

Mid-Water

     64%             68%             72%          

Jack-ups (d)

     76%             53%             47%          

Average daily revenue (e)

            

Floaters:

            

Ultra-Deepwater

   $  344,200           $  354,900           $  342,900          

Deepwater

     403,100             368,800             416,500          

Mid-Water

     275,700             263,600             269,600          

Jack-ups

     88,600             90,200             81,900          

 

(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 and 2011 included approximately 87 days and 720 days, earned by Diamond Offshore’s jack-up rigs during the respective periods prior to being sold in 2012.

(c)

Utilization is calculated as the ratio of total revenue earning 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% and 59% for the years ended December 31, 2012 and 2011, excluding revenue earning days and total calendar days associated with rigs that were sold in 2012.

(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, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included under Item 8:

 

Year Ended December 31    2013      2012      2011      

 

 
(In millions)                     

Revenues:

        

Contract drilling revenues

   $     2,844        $     2,936        $     3,254        

Net investment income

                     7        

Investment gains

           1        

Other

     81          131          73        

 

 

Total

     2,926          3,072          3,335        

 

 

Expenses:

        

Contract drilling expenses

     1,573          1,537          1,549        

Other operating expenses

     554          572          535        

Interest

     25          46          73        

 

 

Total

     2,152          2,155          2,157        

 

 

Income before income tax

     774          917          1,178        

Income tax expense

     (245)         (223)         (250)       

Amounts attributable to noncontrolling interests

     (272)         (357)         (477)       

 

 

Net income attributable to Loews Corporation

   $ 257        $ 337        $ 451        

 

 

2013 Compared with 2012

Contract drilling revenue decreased $92 million in 2013 as compared with 2012, while contract drilling expense increased $36 million during the same period. Contract drilling revenue was negatively impacted by a decrease in revenue earned by Diamond Offshore’s ultra-deepwater and mid-water fleets, partially offset by favorable revenue variances for its deepwater and jack-up rigs. The increase in contract drilling expense reflects higher labor and personnel related costs primarily as a result of mid-2013 pay increases and costs associated with additional crews for Diamond Offshore’s new rigs expected to be delivered in 2014 and for the Ocean Onyx delivered in the fourth quarter of 2013, higher repairs and maintenance and inspection costs, partially offset by decreased mobilization and freight costs.

Revenue generated by ultra-deepwater floaters decreased $48 million in 2013 as compared with 2012, due to lower average daily revenue of $25 million, a decrease in amortized mobilization revenue of $18 million and decreased utilization of $30 million, partially offset by $25 million of revenue recognized in connection with a settlement agreement entered into with a customer. The settlement agreement related to amounts due to Diamond Offshore during 2013 for which revenue of $56 million was not recognized due to the financial condition of the customer. The decrease in average daily revenue is primarily due to a contract extension for the Ocean Rover at a significantly lower dayrate than previously earned. Amortized mobilization fees decreased primarily due to the recognition of mobilization revenue in the 2012 period associated with the Ocean Monarch’s mobilization to Vietnam. The decrease in revenue earning days is primarily due to incremental unplanned downtime, partially offset by a reduction in downtime for shipyard projects and inspection.

Revenue generated by deepwater floaters increased $19 million in 2013 as compared with 2012, as a result of higher average daily revenue of $52 million, partially offset by a decrease in utilization of $28 million and lower amortized mobilization revenue of $5 million. Average daily revenue increased in 2013 primarily due to the Ocean Valiant and Ocean Victory both working at significantly higher dayrates than those rigs earned in 2012. The decline in revenue earning days is due to incremental unscheduled downtime for repairs, scheduled shipyard projects and mobilization of the Ocean America.

 

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Revenue generated by mid-water floaters decreased $77 million in 2013 as compared with 2012, as a result of decreased utilization of $119 million and a reduction in amortized mobilization and contract preparation fees of $8 million, partially offset by higher average daily revenue of $50 million. Revenue earning days decreased primarily due to an increase in planned downtime for shipyard inspections and projects, cold-stacking of a rig, and 136 fewer days for the Ocean Quest and Ocean Lexington for which the associated revenue of $61 million was not recognized due to the financial condition of two of Diamond Offshore’s customers and since collection of the amounts due was not reasonably assured, partially offset by fewer days for the mobilization of rigs. The increase in average daily revenue is primarily due to new contracts and contract renewals for four rigs at higher dayrates than previously earned.

Revenue generated by jack-up rigs increased $14 million in 2013 as compared with 2012, primarily due to utilization of a rig which was warm stacked in 2012 earning $26 million of revenue in 2013, partially offset by the absence of revenue attributable to six jack-up rigs that Diamond Offshore sold in 2012. These rigs earned aggregate revenue of $5 million in 2012. Revenues in 2013 were further reduced by scheduled downtime for repairs for two jack-up rigs.

Net income decreased $80 million in 2013 as compared with 2012 reflecting the decline in revenue, increase in contract drilling expense and recognition of bad debt expense of $23 million, partially offset by lower interest expense. The decrease in interest expense is primarily due to an increase in interest capitalized on eligible construction projects in 2013, partially offset by incremental interest expense for the senior unsecured notes issued in 2013 and interest expense associated with uncertain tax positions in the Mexico tax jurisdiction. Net income for 2012 also included a $32 million gain (after tax and noncontrolling interests) on the sale of six jack-up rigs and an impairment loss of $19 million (after tax and noncontrolling interests) recognized on three mid-water floaters.

Diamond Offshore’s effective tax rate for 2013 increased as compared with 2012. The higher effective tax rate in 2013 is primarily the result of differences in the mix of Diamond Offshore’s domestic and international pretax earnings and losses, as well as the international jurisdictions in which Diamond Offshore operates and a $57 million ($27 million after noncontrolling interests) charge related to an uncertain tax position for Egyptian operations. The increase in the effective rate is partially offset by the recognition of the impact of The American Taxpayer Relief Act of 2012, which reduced 2013 income tax expense by $28 million ($13 million after noncontrolling interests). The Act, which was signed into law on January 2, 2013, extended through 2013 several expired temporary business provisions, commonly referred to as “extenders” which were retroactively extended to the beginning of 2012.

As Diamond Offshore’s rigs frequently operate in different tax jurisdictions as they move from contract to contract, its effective tax rate can fluctuate substantially and its historical effective tax rates may not be sustainable and could increase materially.

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 was 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 was 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.

 

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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 was 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 was primarily due to higher incremental downtime for shipyard projects and inspections as compared with 2011.

Revenue generated by mid-water floaters decreased $207 million in 2012 as compared with 2011, primarily due to a $166 million decrease in utilization, a $28 million decrease in average daily revenue and a $13 million decrease in amortized mobilization fees. Revenue earning days decreased by 615, primarily attributable to planned downtime for mobilization and shipyard projects, unplanned downtime for repairs, the warm stacking of rigs between contracts and additional days a rig was cold-stacked.

Revenue generated by jack-up rigs decreased $37 million in 2012 as compared with 2011, primarily due to the sale of six jack-up rigs in 2012, three of which operated during 2011.

Net income decreased in 2012 as compared with 2011 reflecting a decline in revenue and a $19 million impairment loss (after tax and noncontrolling interests) on three mid-water floaters which were expected to be disposed of in 2013. Net income for 2012 included a $32 million gain (after tax and noncontrolling interests) on the sale of six jack-up rigs. In addition, interest expense decreased $27 million in 2012 as compared with 2011 primarily due to incremental interest costs capitalized during 2012 related to the continuing rig construction projects.

Diamond Offshore’s annual effective tax rate for 2012 increased as compared with 2011. The higher effective tax rate in 2012 was primarily the result of differences in the mix of Diamond Offshore’s domestic and international pretax earnings and losses, the mix of international tax jurisdictions in which Diamond Offshore operates and the impact of a tax law provision that expired at the end of 2011. This provision allowed Diamond Offshore to defer recognition of certain foreign earnings for U.S. tax purposes during 2011, which deferral was unavailable in 2012. Diamond Offshore’s 2011 tax expense also included the reversal of $15 million of U.S. income tax expense, originally recognized in 2010, related to Diamond Offshore’s intention at that time to repatriate certain foreign earnings which changed in 2011 subsequent to its decision to build new drillships overseas.

Boardwalk Pipeline

Boardwalk Pipeline derives revenues primarily from the transportation and storage of natural gas and natural gas liquids (“NGLs”) and gathering and processing of natural gas for third parties. Transportation services consist of firm natural gas transportation, where the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, where the customer pays to transport gas only when capacity is available and used. Boardwalk Pipeline offers firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (“PAL”) services where the customer receives and pays for capacity only when it is available and used. Boardwalk Pipeline’s NGL contracts are generally fee-based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. Boardwalk Pipeline’s NGL storage rates are market based rates and contracts are typically fixed price arrangements with escalation clauses. Boardwalk Pipeline is not in the business of buying and selling natural gas and NGLs other than for system management purposes, but changes in the level of natural gas and NGL prices may impact the volumes of gas transported and stored on its pipeline systems. Boardwalk Pipeline’s operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at its compressor stations.

Market Conditions and Contract Renewals

Boardwalk Pipeline provides natural gas transportation services to customers that are directly connected to its pipeline system and, through interconnects with third party pipelines, to customers that are not directly connected to Boardwalk Pipeline’s system. Transportation rates that Boardwalk Pipeline can charge customers it serves through interconnects with third party pipelines are heavily influenced by current and anticipated basis differentials. Basis

 

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differentials, generally the difference in the price of natural gas at receipt and delivery points across Boardwalk Pipeline’s natural gas pipeline system, influence how much 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, the proximity of supply areas to end use markets, 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 Boardwalk Pipeline’s pipeline systems. New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and the Utica shale plays, which are closer to the traditional high value markets that Boardwalk Pipeline serves than the supply basins connected to Boardwalk Pipeline’s facilities. As a result, pipeline infrastructure has been and continues to be developed to move natural gas and NGLs from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to Boardwalk Pipeline’s pipelines and have caused some of the gas production that is supplied to Boardwalk Pipeline’s system to be diverted to other market areas. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on Boardwalk Pipeline’s pipeline systems have narrowed significantly in recent years, reducing the transportation rates and other contract terms Boardwalk Pipeline can negotiate with its customers for available transportation capacity and for contracts due for renewal for its interruptible and firm transportation services.

A substantial portion of Boardwalk Pipeline’s transportation capacity is contracted for under firm transportation agreements. Each year a portion of Boardwalk Pipeline’s firm transportation agreements expire and needs to be renewed or replaced. Due to the factors noted above, in recent periods Boardwalk Pipeline has renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially adversely impacted its firm and interruptible transportation revenues. In light of the market conditions discussed above, natural gas transportation contracts that Boardwalk Pipeline has renewed or entered into in 2013 and in recent years have been at lower rates, and any remaining available capacity generally has been marketed and sold at lower rates under short term firm or interruptible contracts, or in some cases not sold at all. As a result, capacity reservation charges under firm transportation agreements for the year ended December 31, 2013 were lower by $45 million than they were for 2012. Boardwalk Pipeline expects this trend to continue and therefore may not be able to sell its available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, all of which would continue to adversely impact its transportation revenues, earnings and distributable cash flows and could impact Boardwalk Pipeline on a long term basis.

More recently, Boardwalk Pipeline has seen the value of its storage and PAL services adversely impacted by the factors discussed above, which have contributed to a narrowing of natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the price volatility of natural gas to decline significantly, reducing the rates Boardwalk Pipeline can charge for its storage and PAL services. Based on the current forward pricing curve, which is backwardated, time period price spreads for 2013 have significantly deteriorated from the 2012 levels and Boardwalk Pipeline expects such conditions to persist. In recent months, Boardwalk Pipeline has seen the deterioration of storage spreads accelerate and that trend is expected to continue into 2014. These market conditions, together with regulatory changes in the financial services industry, have also caused a number of gas marketers, which have traditionally been large consumers of Boardwalk Pipeline’s storage and PAL services, to exit the market, further negatively impacting the market for those services. A reduced need for storage as supply increases, narrowing time period price spreads and fewer market participants has caused, and could continue to cause demand for Boardwalk Pipeline’s storage and PAL services to decline on a long term basis.

In February of 2014, Boardwalk Pipeline declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that have been declared and paid in recent prior periods, which reflects the market conditions described above and the resulting cumulative impact on Boardwalk Pipeline’s business from the decline in transportation and storage revenues. Boardwalk Pipeline intends to use the increase in cash that is not distributed to unitholders to fund growth and/or to repay indebtedness. We have offered Boardwalk Pipeline up to $300 million of subordinated loans to fund growth, if it is needed. Boardwalk Pipeline intends to use those sources of capital to fund its growth and reduce its leverage (including its Debt-to-EBITDA ratio) in lieu of issuing additional limited partnership units which would be dilutive to unitholders. Boardwalk Pipeline cannot give assurances that it will complete future growth projects or acquisitions or, if completed, that they will be accretive to its earnings and cash flow, that Boardwalk Pipeline will be successful in reducing its leverage, or that Boardwalk

 

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Pipeline will not issue and sell additional limited partnership units to fund its growth or for other partnership purposes.

Results of Operations

The following table summarizes the results of operations for Boardwalk Pipeline for the years ended December 31, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included under Item 8:

 

Year Ended December 31    2013      2012      2011  

 

 
(In millions)                     

Revenues:

        

Other revenue, primarily operating

   $      1,231          $      1,187          $      1,144        

Net investment income

             

Investment losses

        (3)      

 

 

Total

     1,232          1,184          1,144        

 

 

Expenses:

        

Operating

     776          717          760        

Impairment of goodwill

     52          

Interest

     163          166          173        

 

 

Total

     991          883          933        

 

 

Income before income tax

     241          301          211        

Income tax expense

     (56)         (70)         (57)       

Amounts attributable to noncontrolling interests

     (107)         (122)         (77)       

 

 

Net income attributable to Loews Corporation

   $ 78          $ 109          $ 77        

 

 

2013 Compared with 2012

Total revenues increased $48 million for 2013 as compared with 2012. This increase is primarily due to $63 million of revenues earned from Boardwalk Louisiana Midstream LLC (“Louisiana Midstream”), acquired in October of 2012, a $30 million gain from the sale of storage gas and an increase in fuel revenues of $9 million primarily due to higher natural gas prices. The increase in revenues was partially offset by the market conditions discussed above, resulting in lower transportation revenues, excluding fuel, of $53 million and $4 million of reduced storage and PAL revenues.

Operating expenses increased $59 million for 2013, compared to 2012. This increase is primarily due to $38 million of expenses incurred by Louisiana Midstream, higher depreciation and property taxes of $9 million due to an increase in the asset base and increased fuel costs of $6 million due to higher natural gas prices.

Boardwalk Pipeline recognized a goodwill impairment charge of $52 million ($16 million after tax and noncontrolling interests) for the year ended December 31, 2013, representing the carrying value of goodwill related to its reporting unit which included goodwill associated with the acquisition of Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage Company, LLC) (“Petal”) in December of 2011. The fair value of the reporting unit declined from the amount determined in 2012 primarily due to the recent narrowing of time period price spreads and reduced volatility which negatively affects the value of Boardwalk Pipeline’s storage and PAL services and the cumulative effect of reduced basis spreads on the value of Boardwalk Pipeline’s transportation services.

Net income decreased $31 million for 2013 as compared with 2012 reflecting higher revenues offset by increased expenses as discussed above. The percentage of income attributable to noncontrolling interests increased as a result of equity offerings in 2012 and 2013 by Boardwalk Pipeline, decreasing our ownership percentage from 59% in 2012 to 54% in 2013.

 

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2012 Compared with 2011

Total revenues increased $40 million in 2012 as compared with 2011, primarily due to $63 million of revenues earned by Petal and Louisiana Midstream and higher PAL and storage revenues of $14 million resulting from improved market conditions. The increase in revenues was partially offset by a decrease in retained fuel of $34 million primarily due to lower natural gas prices.

Operating expenses decreased $43 million in 2012 as compared with 2011. The primary drivers of the decrease were charges incurred in 2011 including a $29 million impairment charge associated with Boardwalk Pipeline’s materials and supplies, an expense of $5 million representing an insurance deductible associated with replacing compressor assets and $4 million of gas losses associated with the Bistineau storage facility. In addition, in the 2012 period there were lower fuel costs of $21 million due to lower natural gas prices, lower general and administrative expenses of $16 million as a result of cost management activities and lower operation and maintenance expenses of $11 million primarily from lower maintenance project costs and outside services. These decreases were partially offset by $38 million of expenses incurred by Petal and Louisiana Midstream and $9 million of asset impairment charges. The 2011 period included a gain of $9 million from the sale of storage gas. Interest expense decreased $7 million for 2012, primarily from a charge recorded in 2011 on the early extinguishment of debt, partially offset by increased debt levels and higher average interest rates.

HighMount

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

 

Bbl    -   Barrel (of oil or NGLs)
Bcf    -   Billion cubic feet (of natural gas)
Bcfe    -   Billion cubic feet of natural gas equivalent
Mbbl    -   Thousand barrels (of oil or NGLs)
Mcf    -   Thousand cubic feet (of natural gas)
Mcfe    -   Thousand cubic feet of natural gas equivalent
MMBtu    -   Million British thermal units

HighMount’s revenues and profitability depend substantially on natural gas and oil prices and HighMount’s ability to increase its natural gas and oil production. Natural gas and NGL prices remain at low levels due to an increase in the supply of natural gas and NGL resulting from new sources of supply recoverable from shale formations, primarily the result of technological advancements in horizontal drilling and hydraulic fracturing. As a result, it has become uneconomical for HighMount to drill new natural gas wells which has led it to change its capital investments strategy from natural gas production to exploration and development of potential oil producing properties. HighMount has drilled a number of exploratory wells on its properties in the Mississippian Lime and Woodford Shale plays in Oklahoma and in the Wolfcamp zone of its Sonora acreage. Exploration of potential oil producing properties, including drilling and completion of horizontal wells, carries more risk and is significantly more expensive than drilling traditional vertical natural gas-producing wells. HighMount is not currently drilling new wells on its Oklahoma properties and has one drilling rig working in the Wolfcamp area. To date, these exploratory wells have not yielded sufficient quantities of oil to support commercial development of these properties. Further study and refinement of drilling techniques will be required in order to determine whether there is an economic development opportunity. HighMount has incurred substantial ceiling test and other impairment charges as a result of the market conditions and drilling efforts discussed above and could incur significant additional impairment charges in the future if these conditions continue or HighMount’s efforts to develop sufficient new proved reserves are not successful.

 

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The focus on exploring oil producing properties has led to a reduction in natural gas and NGL production and an increase in oil production. Natural gas production at HighMount has declined from 45.4 Bcf in 2011 to 33.0 Bcf in 2013. Revenues from the sale of oil, including the impact of hedges, amounted to 20% of HighMount’s total revenues for the year ended December 31, 2013 as compared to 15% and 7% of its total revenue for the years ended December 31, 2012 and 2011. The price HighMount realizes for its production is also affected by HighMount’s hedging activities, as well as locational differences in market prices.

HighMount’s operating expenses consist primarily of production expenses, production and ad valorem taxes, as well as depreciation, depletion and amortization (“DD&A”) expenses. Production expenses represent costs incurred to operate and maintain wells, related equipment and facilities and transportation costs and contain a significant fixed cost component. Production expenses per Mcfe increased primarily as a result of lower natural gas and NGL production that has absorbed HighMount’s fixed costs. HighMount’s increased focus on oil production also contributed to the increase in production cost per Mcfe due to HighMount’s oil projects generally requiring a higher cost to produce per equivalent unit than HighMount’s gas projects. Production and ad valorem taxes increase or decrease primarily when prices of natural gas and oil increase or decrease, but they are also affected by changes in production and state incentive programs, as well as appreciated property values. HighMount calculates depletion using the units-of-production method, which depletes the capitalized costs and future development costs associated with evaluated properties based on the ratio of production volumes for the current period to total remaining reserve volumes for the evaluated properties. HighMount’s depletion expense is affected by its capital spending program and projected future development costs, as well as reserve changes resulting from drilling programs, well performance and revisions due to changing commodity prices.

Production and Sales Statistics

Presented below are production and sales statistics related to HighMount’s operations for 2013, 2012 and 2011:

 

Year Ended December 31    2013      2012      2011  

 

 

Gas production (Bcf)

     33.0           39.1           45.4         

Gas sales (Bcf)

     30.6           36.6           42.7         

NGL production/sales (Mbbls)

         2,002.2               2,357.2               2,693.7         

Oil production/sales (Mbbls)

     563.6           501.0           282.2         

Equivalent production (Bcfe)

     48.4           56.2           63.3         

Equivalent sales (Bcfe)

     46.0           53.7           60.6         

Average realized prices without hedging results:

        

Gas (per Mcf)

   $ 3.53       $ 2.67       $ 3.94       

NGL (per Bbl)

     31.84         37.35         52.70       

Oil (per Bbl)

     93.18         86.29         89.43       

Equivalent (per Mcfe)

     4.87         4.26         5.54       

Average realized prices with hedging results:

        

Gas (per Mcf)

   $ 4.23       $ 4.24       $ 5.84       

NGL (per Bbl)

     36.05         38.36         39.60       

Oil (per Bbl)

     92.97         91.41         89.43       

Equivalent (per Mcfe)

     5.52         5.42         6.30       

Average cost per Mcfe:

        

Production expenses

   $ 1.66       $ 1.33       $ 1.20       

Production and ad valorem taxes

     0.27         0.23         0.39       

General and administrative expenses

     0.86         0.76         0.68       

Depletion expense

     1.13         1.45         1.18       

 

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Results of Operations

The following table summarizes the results of operations for HighMount for the years ended December 31, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included in Item 8.

 

Year Ended December 31    2013        2012      2011    

 

 
(In millions)                     

Revenues:

        

Other revenue, primarily operating

   $       260            $       297            $       390        

Investment losses

     (1)            (34)       

 

 

Total

     259          297          356        

 

 

Expenses:

        

Impairment of goodwill

     584          

Other operating expenses

        

Impairment of natural gas and oil properties

     291          680       

Operating

     252          239          245        

Interest

     17          14          46        

 

 

Total

     1,144          933          291        

 

 

Income (loss) before income tax

     (885)         (636)         65        

Income tax (expense) benefit

     311          229          (24)       

 

 

Net income (loss) attributable to Loews Corporation

   $ (574)           $ (407)           $ 41        

 

 

For the years ended December 31, 2013 and 2012, HighMount recorded ceiling test impairment charges of $291 million and $680 million ($186 million and $433 million after tax). The 2013 write-downs were primarily attributable to negative reserve revisions due to variability in well performance where HighMount is testing different horizontal target zones and hydraulic fracture designs and due to reduced average NGL prices used in the ceiling test calculations. The 2012 write-downs were the result of declines in natural gas and NGL prices. The December 31, 2013 ceiling test calculation was based on average 2013 prices of $3.67 per MMBtu for natural gas, $35.39 per Bbl for NGLs and $96.94 per Bbl for oil. The December 31, 2012 ceiling test calculation was based on average 2012 prices of $2.76 MMBtu for natural gas, $41.11 per Bbl for NGLs and $94.71 per Bbl for oil. Low natural gas and NGL prices, which are not anticipated to improve in the near term, and high drilling and completion costs of horizontal wells targeting oil reserves, compared to traditional vertical gas wells, as well as lower than anticipated production from recently completed wells, have adversely impacted HighMount’s results of operations and cash flows. The continuation of these factors could result in ceiling test impairment charges in future periods, which may be material.

Recognition of a ceiling test impairment charge is considered a triggering event for purposes of assessing any potential impairment of goodwill. The quantitative goodwill impairment analysis is a two-step process. The first step compares HighMount’s estimated fair value to its carrying value. Due to the continued low market prices for natural gas and NGLs, the recent history of quarterly ceiling test write-downs during 2012 and 2013 and potential for future impairments, and negative reserve revisions recognized during 2013, HighMount reassessed its goodwill impairment analysis. To determine fair value, HighMount used a market approach which required significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, earnings before interest, tax, depreciation and amortization, production and reserves, control premium, discount rates and required capital expenditures. These valuation techniques were based on analysis of comparable public companies, adjusted for HighMount’s growth profile. In the first step, HighMount determined that its carrying value exceeded its fair value requiring HighMount to perform the second step and to estimate the fair value of its assets and liabilities. The carrying value of goodwill is limited to the amount that HighMount’s estimated fair value exceeds the fair value of assets and liabilities. As a result, HighMount recorded a goodwill impairment charge of $584 million ($382 million after tax) for the year ended December 31, 2013, consisting of all of its remaining goodwill.

 

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2013 Compared with 2012

HighMount’s operating revenues decreased $37 million for 2013 as compared with 2012 primarily due to reduced natural gas and NGL sales volumes and reduced NGL sales prices. HighMount sold 46.0 Bcfe in 2013 compared to 53.7 Bcfe in 2012. The decrease in sales volume was primarily due to the discontinued drilling of conventional vertical natural gas wells in recent years, as well as reduced maintenance of existing producing wells.

HighMount had hedges in place as of December 31, 2013 that covered approximately 59.9% and 20.9% of its total estimated 2014 and 2015 natural gas equivalent production at a weighted average price of $5.52 and $4.24 per Mcfe.

Operating expenses increased by $13 million for 2013 as compared with 2012 primarily as a result of an impairment charge of $34 million related to HighMount’s gathering pipelines in the Permian Basin due to low natural gas and NGL prices and decreased production, partially offset by lower DD&A expenses due to the impairment of natural gas and oil properties recorded in 2013 and 2012.

2012 Compared with 2011

HighMount’s operating revenues decreased $93 million in 2012 as compared with 2011 due to decreased natural gas and NGL prices and sales volumes. Average prices realized per Mcfe were $5.42 in 2012 compared to $6.30 in 2011. HighMount sold 53.7 Bcfe in 2012 compared to 60.6 Bcfe in 2011. The decrease in sales volume was primarily due to the continued reduction in capital spending on natural gas drilling since 2008.

HighMount had hedges in place as of December 31, 2012 that covered approximately 59.5% and 26.6% of its total estimated 2013 and 2014 natural gas equivalent production at a weighted average price of $6.27 and $5.39 per Mcfe.

Operating expenses were $239 million and $245 million in 2012 and 2011. Production expenses and production and ad valorem taxes were $98 million in 2012 as compared with $109 million in 2011. DD&A expenses were $101 million in 2012 as compared with $94 million in 2011. The increase in DD&A expenses was primarily due to negative reserve revisions in 2011 and projected future development activity focused on developing oil reserves.

In connection with refinancing its $1.1 billion variable rate term loans, a pretax loss of $34 million was recorded in the fourth quarter of 2011, reflecting derivative losses from termination of interest rate hedge activities. Interest expense decreased $32 million in 2012 as compared with 2011 due to a lower outstanding debt balance in 2012.

 

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Loews Hotels

The following table summarizes the results of operations for Loews Hotels for the years ended December 31, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included under Item 8:

 

Year Ended December 31      2013        2012        2011      

 

 
(In millions)                           

Revenues:

              

Other revenue, primarily operating

     $         380          $         396          $     336        

Net investment income

                      1        

 

 

Total

       380            397            337        

 

 

Expenses:

              

Other operating expenses

              

Operating

       356            366            306        

Depreciation

       32            30            29        

Equity income from joint ventures

       (13)           (24)           (24)       

Interest

                 11            9        

 

 

Total

       384            383            320        

 

 

Income (loss) before income tax

       (4)           14            17        

Income tax (expense) benefit

                 (7)           (4)       

 

 

Net income (loss) attributable to Loews Corporation

     $ (3)         $         $ 13        

 

 

EBITDA

     $ 37          $ 55          $ 55        

 

 

Earnings before interest, tax, depreciation and amortization (“EBITDA”) is an indicator of operating performance used by Loews Hotels to measure its ability to service debt, fund capital expenditures and expand its business. EBITDA is a non-GAAP financial measure that is not meant to replace net income as defined by GAAP. The following table reconciles EBITDA to Net income attributable to Loews Corporation for the years ended December 31, 2013, 2012 and 2011.

 

Year Ended December 31      2013            2012            2011      

 

 
(In millions)                           

EBITDA

     $           37              $           55              $ 55        

Depreciation

       (32)               (30)               (29)       

Interest

       (9)               (11)               (9)       

Income tax (expense) benefit

       1                (7)               (4)       

 

 

Net income (loss) attributable to Loews Corporation

     $ (3)             $ 7              $       13        

 

 

Results of operations for 2013 as compared to 2012 include the impact of the 2013 closure of the Loews Regency Hotel for renovation and the addition of the Loews Madison Hotel and the Loews Boston Hotel in 2013 to the portfolio of owned hotels for approximately six months. In July of 2013, partial equity interests in the Loews Madison Hotel and the Loews Boston Hotel were sold. Results for 2012 include the Loews Hollywood Hotel for approximately five months prior to a partial equity interest sale in November of 2012. Upon the sale of the equity interests, Loews Hotels’ share of earnings for these hotels is included in Equity income from joint ventures.

 

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Revenues and operating expenses for 2013 and 2012 include $57 million and $27 million of cost reimbursements from joint venture and managed properties, relating mainly to payroll incurred on behalf of the owners of hotel properties managed by Loews Hotels.

2013 Compared with 2012

Revenues excluding reimbursables decreased by $47 million in 2013 as compared to 2012, primarily due to the 2013 closure of the Loews Regency Hotel.

Revenue per available room (“RevPAR”) is an industry measure of the combined effect of occupancy rates and average room rates on room revenues. Other hotel operating revenues, not included in RevPAR, primarily include guest charges for food and beverages. RevPAR, occupancy rates and average room rates as discussed below are for owned and joint venture hotels. RevPAR decreased $5.41 to $168.67 for 2013 as compared to 2012 reflecting a decrease in occupancy and average room rates. Occupancy rates decreased to 75.2% in 2013 from 76.3% in 2012. Average room rates decreased by $3.60, or 1.6%, in 2013 as compared to 2012. Excluding the Loews Regency Hotel which was closed for renovation throughout 2013, RevPAR increased $3.76 for 2013 as compared to 2012, reflecting an increase in average room rates.

Operating expenses excluding reimbursables decreased $40 million for 2013 as compared to 2012, primarily due to the closure of the Loews Regency Hotel, partially offset by higher corporate expenses related to hotels recently acquired and under development. In addition, expenses were reduced by $3 million and $7 million in 2013 and 2012 related to recoveries of a loan guarantee payment.

Equity earnings from joint venture properties decreased in 2013 as compared to 2012, primarily due to the impact of renovations and the development of joint venture properties.

2012 Compared with 2011

Revenues excluding reimbursables increased by $33 million in 2012 as compared to 2011, primarily due to the addition of the Loews Hollywood Hotel in 2012 and higher RevPAR.

Owned and joint venture hotels RevPAR increased $8.93 to $174.08 in 2012 as compared to 2011 reflecting improving occupancy and average room rates; occupancy rates increased to 76.3% in 2012 from 73.6% in 2011; and average room rates increased by $3.65, or 1.6%, in 2012 as compared to 2011.

Operating expenses excluding reimbursables increased $33 million in 2012 as compared to 2011, primarily due to expenses from the Loews Hollywood Hotel and $13 million of costs related to the 2013 closure of the Loews Regency Hotel for renovation, partially offset by $7 million related to the partial recovery of a loan guarantee payment.

 

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Corporate and Other

Corporate and Other operations consist primarily of investment income at the Parent Company, corporate interest expenses and other corporate administrative costs. Investment income includes earnings on cash and short term investments held at the Parent Company level to meet current and future liquidity needs, as well as results of limited partnership investments and the trading portfolio.

The following table summarizes the results of operations for Corporate and Other for the years ended December 31, 2013, 2012 and 2011 as presented in Note 22 of the Notes to Consolidated Financial Statements included under Item 8:

 

Year Ended December 31    2013      2012      2011  

 

 
(In millions)                     

Revenues:

        

Net investment income

   $         141        $           61        $             1        

Other

                     (2)       

 

 

Total

     143          62          (1)       

 

 

Expenses:

        

Operating

     98          106          87        

Interest

     62          40          44        

 

 

Total

     160          146          131        

 

 

Loss before income tax

     (17)         (84)         (132)       

Income tax benefit

             29          47        

 

 

Net loss attributable to Loews Corporation

   $ (10)       $ (55)       $ (85)       

 

 

2013 Compared with 2012

Net investment income increased by $80 million in 2013 as compared to 2012, primarily due to improved performance of the equity and fixed income investments in the trading portfolio and improved performance of limited partnership investments for 2013.

Interest expense increased $22 million for 2013, primarily due to a May of 2013 public offering of $500 million aggregate principal amount of 2.6% senior notes due May 15, 2023 and $500 million aggregate principal amount of 4.1% senior notes due May 15, 2043.

Net results improved $45 million for 2013 as compared to 2012, primarily due to the change in revenues and expenses discussed above.

2012 Compared with 2011

Net investment income increased by $60 million for 2012 as compared to 2011, primarily due to improved performance of equity and fixed income investments in the trading portfolio, partially offset by lower performance of limited partnership investments for 2012.

Net results improved $30 million for 2012 as compared to 2011. These changes were due primarily to the change in revenues discussed above, partially offset by an increase in corporate overhead expenses and reduced corporate overhead allocated to our subsidiaries.

 

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LIQUIDITY AND CAPITAL RESOURCES

CNA Financial

Cash Flows

CNA’s primary operating cash flow sources are premiums and investment income from its insurance subsidiaries. CNA’s primary operating cash flow uses are payments for claims, policy benefits and operating expenses, including interest expense on corporate debt. Additionally, cash may be paid or received for income taxes.

For 2013, net cash provided by operating activities was $1.2 billion as compared with $1.3 billion for 2012. Tax payments were $129 million in 2013 as compared to tax recoveries of $29 million in 2012. Additionally, increased premium receipts were partially offset by increased claim payments.

Net cash provided by operating activities was $1.7 billion in 2011. Cash flows resulting from reinsurance contract commutations are reported as operating activities. Operating cash flows were increased by $547 million in 2011 related to net cash inflows from commutations.

Cash flows from investing activities include the purchase and disposition of available-for-sale financial instruments. Additionally, cash flows from investing activities may include the purchase and sale of businesses, land, buildings, equipment and other assets not generally held for resale.

Net cash used by investing activities was $898 million for 2013, as compared with $934 million and $1.1 billion for 2012 and 2011. The cash flow from investing activities is impacted by various factors such as the anticipated payment of claims, financing activity, asset/liability management and individual security buy and sell decisions made in the normal course of portfolio management.

Cash flows from financing activities may include proceeds from the issuance of debt and equity securities, outflows for shareholder dividends or repayment of debt and outlays to reacquire equity instruments. Net cash used by financing activities was $264 million, $239 million and $644 million for 2013, 2012 and 2011.

Liquidity

CNA believes that its present cash flows from operations, investing activities and financing activities are sufficient to fund its current and expected working capital and debt obligation needs and CNA does not expect this to change in the near term. There are currently no amounts outstanding under CNA’s $250 million senior unsecured revolving credit facility and no borrowings outstanding through CNA’s membership in the Federal Home Loan Bank of Chicago (“FHLBC”).

CNA has an effective Registration Statement on Form S-3 registering the future sale of an unlimited amount of its debt and equity securities.

Dividends

Dividends of $0.80 per share of CNA’s common stock were declared and paid in 2013. On February 7, 2014, CNA’s Board of Directors declared a quarterly dividend of $0.25 per share and a special dividend of $1.00 per share, payable March 12, 2014 to shareholders of record on February 24, 2014. The declaration and payment of future dividends is at the discretion of CNA’s Board of Directors and will depend on many factors, including CNA’s earnings, financial condition, business needs, and regulatory constraints.

Ratings

Ratings are an important factor in establishing the competitive position of insurance companies. CNA’s insurance company subsidiaries are rated by major rating agencies and these ratings reflect the rating agency’s opinion of the insurance company’s financial strength, operating performance, strategic position and ability to meet its obligations to policyholders. Agency ratings are not a recommendation to buy, sell or hold any security, and may be revised or

 

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withdrawn at any time by the issuing organization. Each agency’s rating should be evaluated independently of any other agency’s rating. One or more of these agencies could take action in the future to change the ratings of CNA’s insurance subsidiaries.

The table below reflects the various group ratings issued by A.M. Best Company (“A.M. Best”), Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s (“S&P”) for the property and casualty and life companies. The table also includes the ratings for CNA senior debt.

 

     Insurance Financial Strength Ratings    Corporate Debt Ratings

 

     Property & Casualty    Life    CNA

 

     CCC
Group
   Western
Group
   CAC    Senior Debt

 

A.M. Best

   A    A    A-    bbb

Moody’s

   A3    Not rated    Not rated    Baa2

S&P

   A    A    Not rated    BBB

A.M. Best, Moody’s and S&P each maintain a stable outlook on CNA. In June of 2013, S&P upgraded CNA’s property and casualty insurance financial strength ratings to A and upgraded the credit rating on the senior debt of CNA to BBB. In December 2013, Moody’s revised their outlook on CNA’s financial strength rating to stable from positive.

Hardy benefits from the collective financial strength of the Lloyd’s market, which is rated A+ by S&P and A by A.M. Best. The outlook by both rating agencies is positive.

Diamond Offshore

Cash and investments totaled $2.1 billion at December 31, 2013, compared to $1.5 billion at December 31, 2012. In 2013, Diamond Offshore paid cash dividends totaling $490 million, consisting of aggregate regular cash dividends of $69 million and aggregate special cash dividends of $421 million. On February 5, 2014, Diamond Offshore declared a regular quarterly dividend of $0.125 per share and a special dividend of $0.75 per share.

Cash provided by operating activities in 2013 was $1.1 billion, compared to $1.3 billion in 2012, a decrease of $245 million compared to the 2012 period, primarily due to lower earnings.

 

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Diamond Offshore is currently obligated under various agreements in connection with the construction of three ultra-deepwater drillships, an ultra-deepwater floater, a deepwater floater, and a North Sea enhancement project. The Ocean Onyx and the Ocean BlackHawk were delivered in December of 2013 and January of 2014 and the final installments on these construction contracts aggregating $403 million were paid in January of 2014. The following is a summary of Diamond Offshore’s remaining construction projects as of February 5, 2014:

 

(In millions)    Expected
Delivery (a)
   Total Project
Cost (b)
     Project
Expenditures
to date (c)
 

 

 

New rig construction:

        

Ultra-deepwater drillships:

        

Ocean BlackHornet

   Q2 2014    $ 635             $ 204          

Ocean BlackRhino

   Q3 2014      645               189          

Ocean BlackLion

   Q1 2015      655               171          

Ultra-deepwater floater:

        

Ocean GreatWhite

   Q1 2016      755               190          

Deepwater floater:

        

Ocean Apex

   Q3 2014      370               269