LOEWS CORP
Item 1. Business.
We are a holding company. Our subsidiaries are engaged in the following lines of business:
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commercial property and casualty insurance (CNA Financial Corporation, a 90% owned subsidiary);
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operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc., a 50.4% owned subsidiary);
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exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC, a wholly owned subsidiary);
•
interstate transportation and storage of natural gas (Boardwalk Pipeline Partners, LP, a 61% owned subsidiary); and
•
operation of hotels (Loews Hotels Holding Corporation, a wholly owned subsidiary).
Please read information relating to our major business segments from which we derive revenue and income contained in Note 20 of the Notes to Consolidated Financial Statements, included under Item 8.
CNA FINANCIAL CORPORATION
CNA Financial Corporation (together with its subsidiaries, “CNA”) was incorporated in 1967 and is an insurance holding company. CNA’s property and casualty and remaining life & group insurance operations are primarily conducted by Continental Casualty Company (“CCC”), incorporated in 1897, and The Continental Insurance Company (“CIC”), organized in 1853, and certain other affiliates. CIC became a subsidiary of CNA in 1995 as a result of the acquisition of The Continental Corporation (“Continental”). CNA accounted for 63.4%, 63.0% and 60.0% of our consolidated total revenue for the years ended December 31, 2011, 2010 and 2009.
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, associations, professionals and other groups.
CNA’s core business, commercial property and casualty insurance operations, is reported in two business segments: CNA Specialty and CNA Commercial. CNA’s non-core businesses are managed in two business segments: Life & Group Non-Core and Other Insurance. Each segment is managed separately due to differences in their product lines and markets.
CNA’s property and casualty field structure consists of 48 underwriting locations across the United States. 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 office locations handling the more complex claims. In addition, CNA has underwriting and claim capabilities in Canada and Europe.
CNA Specialty
CNA Specialty provides professional and management liability and other coverages through property and casualty products and services, both domestically and abroad, through a network of brokers, independent agencies and managing general underwriters. CNA Specialty provides solutions for managing the risks of its clients, including architects,
lawyers, accountants, health care professionals, financial intermediaries and public and private companies. Product offerings also include surety and fidelity bonds and warranty services.
CNA Specialty includes the following business groups:
Professional & Management Liability: Professional & Management Liability provides management and professional liability insurance and risk management services and other specialized property and casualty coverages in the United States. This group provides professional liability coverages to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. Professional & Management Liability also provides directors and officers (“D&O”), employment practices, fiduciary and fidelity coverages. Specific areas of focus include small and mid-size firms as well as privately held firms and not-for-profit organizations, where tailored products for this client segment are offered. Products within Professional & Management Liability are distributed through brokers, independent agents and managing general underwriters. Professional & Management Liability, through CNA HealthPro, also offers insurance products to serve the health care industry. Products include professional liability and associated standard property and casualty coverages, and are distributed on a national basis through brokers, independent agents and managing general underwriters. Key customer segments include long term care facilities, allied health care providers, life sciences, dental professionals and mid-size and large health care facilities.
International: International provides similar management and professional liability insurance and other specialized property and casualty coverages 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.
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. These products are distributed through and administered by CNA’s wholly owned subsidiary, CNA National Warranty Corporation, or through third party administrators.
CNA Commercial
CNA Commercial works with an independent agency distribution system and a network of brokers to market a broad range of property and casualty insurance products and services to small, middle-market and large businesses and organizations domestically and abroad. Property products include standard and excess property coverages, as well as marine coverage, and boiler and machinery. Casualty products include standard casualty insurance products such as workers’ compensation, general and product liability, commercial auto and umbrella coverages. Most insurance programs are provided on a guaranteed cost basis; however, CNA also offers specialized loss-sensitive insurance programs to those customers viewed as higher risk and less predictable in exposure.
These property and casualty products are offered as part of CNA’s Small Business, Commercial and International insurance groups. CNA’s Small Business insurance group serves its smaller commercial accounts and the Commercial insurance group serves CNA’s middle markets and its larger risks. In addition, CNA Commercial provides total risk management services relating to claim and information services to the large commercial insurance marketplace, through a wholly owned subsidiary, CNA ClaimPlus, Inc., a third party administrator. The International insurance group primarily consists of the commercial product lines of CNA’s operations in Europe and Canada.
Also included in CNA Commercial is CNA Select Risk (“Select Risk”), which includes CNA’s excess and surplus lines coverages. Select Risk provides specialized insurance for selected commercial risks on both an individual customer and program basis. Customers insured by Select Risk are generally viewed as higher risk and less predictable in exposure than those covered by standard insurance markets. Select Risk’s products are distributed throughout the United States through specialist producers, program agents and brokers.
Life & Group Non-Core
The Life & Group Non-Core segment primarily includes the results of the life and group lines of business that are in run-off. CNA continues to service its existing individual long term care commitments, its payout annuity business and its pension deposit business. CNA also retains a block of group reinsurance and life settlement contracts. These businesses are being managed as a run-off operation. CNA’s group long term care business, while considered non-core, continues to accept new employees in existing groups.
Other Insurance
Other Insurance primarily includes certain CNA corporate expenses, including interest on CNA corporate debt, and the results of certain property and casualty business in run-off, including CNA Re and asbestos and environmental pollution (“A&EP”). In 2010, CNA ceded substantially all of its legacy A&EP liabilities under the Loss Portfolio Transfer, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
Please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations by Business Segment - CNA Financial” for information with respect to each segment.
Direct Written Premiums by Geographic Concentration
Set forth below is the distribution of CNA’s direct written premiums by geographic concentration.
(a) No other individual state, country or political subdivision accounts for more than 3.0% of direct written premiums.
Approximately 8.8%, 6.9% and 7.0% of CNA’s direct written premiums were derived from outside of the United States for the years ended December 31, 2011, 2010 and 2009.
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.
The loss reserve development table is cumulative and, therefore, ending balances should not be added since the amount at the end of each calendar year includes activity for both the current and prior years. The development amounts in the table below include the impact of reinsurance commutations, but exclude the impact of the allowance for doubtful accounts on reinsurance receivables.
(a) Effective October 31, 2002, CNA sold CNA Reinsurance Company Limited. As a result of the sale, net reserves were reduced by $1.3 billion.
(b) Effective January 1, 2010, CNA ceded approximately $1.5 billion of net asbestos and environmental pollution (“A&EP”) claim and allocated claim adjustment expense reserves relating to its continuing operations under a retroactive reinsurance agreement with an aggregate limit of $4.0 billion, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
Please read information relating to CNA’s property and casualty claim and claim adjustment expense reserves and reserve development set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), and in Notes 1 and 8 of the Notes to Consolidated Financial Statements, included under Item 8.
Investments
Please read Item 7, MD&A - Investments and Notes 1, 3, 4 and 5 of the Notes to Consolidated Financial Statements, included under Item 8.
Other
Competition: The property and casualty insurance industry is highly competitive both as to rate and service. CNA competes with a large number of stock and mutual insurance companies and other entities for both distributors and customers. Insurers compete on the basis of factors including products, price, services, ratings and financial strength. CNA must continuously allocate resources to refine and improve its insurance products and services.
There are approximately 2,500 individual companies that sell property and casualty insurance in the United States. Based on 2010 statutory net written premiums, CNA is the seventh largest commercial insurance writer and the 13th largest property and casualty insurance organization in the United States.
Regulation: The insurance industry is subject to comprehensive and detailed regulation and supervision. Each domestic and foreign jurisdiction has established supervisory agencies with broad administrative powers relative to licensing insurers and agents, approving policy forms, establishing reserve requirements, prescribing the form and content of statutory financial reports, and regulating capital adequacy and the type, quality and amount of investments permitted. Such regulatory powers also extend to premium rate regulations, which require that rates not be excessive, inadequate or unfairly discriminatory. In addition to regulation of dividends by insurance subsidiaries, intercompany transfers of assets may be subject to prior notice or approval by insurance regulators, depending on the size of such transfers and payments in relation to the financial position of the insurance subsidiaries making the transfer or payment.
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 the activities of the IAIS will impact CNA or U.S. insurance regulation.
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.
Although the federal government does not directly regulate the business of insurance, federal legislative and regulatory initiatives can impact the insurance industry in a variety of ways. These initiatives and legislation include tort reform proposals; proposals addressing natural catastrophe exposures; terrorism risk mechanisms; federal financial services reforms; various tax proposals affecting insurance companies; and possible regulatory limitations, impositions and restrictions arising from the Dodd-Frank Wall Street Reform and Consumer Protection Act, as well as the Patient Protection and Affordable Care Act, both enacted in 2010.
Various legislative and regulatory efforts to reform the tort liability system have, and will continue to, impact CNA’s industry. Although there has been some tort reform with positive impact to the insurance industry, new causes of action and theories of damages continue to be proposed in state court actions or by federal or state legislatures that continue to expand liability for insurers and their policyholders. For example, some state legislatures have from time to time considered legislation addressing direct actions against insurers related to bad faith claims. As a result of this unpredictability in the law, insurance underwriting is expected to continue to be difficult in commercial lines, professional liability and other specialty coverages.
The Dodd-Frank Wall Street Reform and Consumer Protection Act expands the federal presence in insurance oversight and may increase the regulatory requirements to which CNA may be subject. The Act’s requirements include streamlining the state-based regulation of reinsurance and nonadmitted insurance (property or casualty insurance placed from insurers that are eligible to accept insurance, but are not licensed to write insurance in a particular state). The Act also establishes a new Federal Insurance Office within the U.S. Department of the Treasury with powers over all lines of insurance except health insurance, certain long term care insurance and crop insurance, to, among other things, monitor aspects of the insurance industry, identify issues in the regulation of insurers that could contribute to a systemic crisis in the insurance industry or the overall financial system, coordinate federal policy on international insurance matters and preempt state insurance measures under certain circumstances. The Act calls for numerous studies and contemplates further regulation.
The Patient Protection and Affordable Care Act and the related amendments in the Health Care and Education Reconciliation Act may increase CNA’s operating costs and underwriting losses. This landmark legislation may lead to numerous changes in the health care industry that could create additional operating costs for CNA, particularly with respect to its workers’ compensation and long term care products. These costs might arise through the increased use of health care services by CNA’s claimants or the increased complexities in health care bills that could require additional levels of review. In addition, due to the expected number of new participants in the health care system and the potential for additional malpractice claims, CNA may experience increased underwriting risk in the lines of its business that provide management and professional liability insurance to individuals and businesses engaged in the health care industry. The lines of CNA’s business that provide professional liability insurance to attorneys, accountants and other professionals who advise clients regarding the health care reform legislation may also experience increased underwriting risk due to the complexity of the legislation.
Properties: The Chicago location houses CNA’s principal executive offices. CNA’s subsidiaries own or lease office space in various cities throughout the United States and in other countries. The following table sets forth certain information with respect to CNA’s principal office locations:
Location
Size
(square feet)
Principal Usage
333 S. Wabash Avenue
Chicago, Illinois
774,832
Principal executive offices of CNA
401 Penn Street
Reading, Pennsylvania
171,341
Property and casualty insurance offices
2405 Lucien Way
Maitland, Florida
112,708
Property and casualty insurance offices
40 Wall Street
New York, New York
112,336
Property and casualty insurance offices
101 S. Phillips Avenue
Sioux Falls, South Dakota
83,616
Property and casualty insurance offices
600 N. Pearl Street
Dallas, Texas
62,275
Property and casualty insurance offices
4267 Meridian Parkway
Aurora, Illinois
46,903
Data center
4150 N. Drinkwater Boulevard
Scottsdale, Arizona
46,499
Property and casualty insurance offices
675 Placentia Avenue
Brea, California
44,237
Property and casualty insurance offices
2435 Commerce Avenue
Duluth, Georgia
43,019
Property and casualty insurance offices
CNA leases its office space described above except for the buildings in Chicago, Illinois, Reading, Pennsylvania and Aurora, Illinois, which are owned.
DIAMOND OFFSHORE DRILLING, INC.
Diamond Offshore Drilling, Inc. (“Diamond Offshore”) is engaged, through its subsidiaries, in the business of owning and operating drilling rigs that are used in the drilling of offshore oil and gas wells on a contract basis for companies engaged in exploration and production of hydrocarbons. Diamond Offshore accounted for 23.6%, 23.0% and 25.9% of our consolidated total revenue for the years ended December 31, 2011, 2010 and 2009.
Rigs: Diamond Offshore owns 49 offshore rigs, consisting of 32 semisubmersible rigs, 13 jack-ups and four dynamically positioned drillships, three of which are under construction with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. Diamond Offshore’s diverse fleet enables it to offer a broad range of services worldwide in both the floater market (ultra-deepwater, deepwater and mid-water) and the non-floater, or jack-up, market.
A floater rig is a type of mobile offshore drilling unit that floats and does not rest on the seafloor. This asset class includes self-propelled drillships and semisubmersible rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersible rigs hold position while drilling by use of a series of small propulsion units or thrusters that provide dynamic positioning (“DP”) to keep the rig on location, or with anchors tethered to the sea bed. While DP semisubmersibles are self-propelled, such rigs may be moved long distances with the assistance of tug boats, while 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 dynamic-positioning 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
Nominal Water Depth (a) (in feet)
Number of Units in Fleet (b)
Ultra-Deepwater
7,501 to 12,000
11 (c)
Deepwater
5,000 to 7,500
6 (d)
Mid-Water
400 to 4,999
(a) Nominal water depth for semisubmersibles and drillships reflects the current operating water depth capability for each drilling rig. However, individual rigs are capable of drilling, or have drilled, in marginally greater water depths depending on conditions (such as salinity of the ocean, weather and sea conditions). On a case by case basis, Diamond Offshore may achieve even greater depth capacity by providing additional equipment.
(b) Includes seven ultra-deepwater, one deepwater and one mid-water dynamically positioned rigs.
(c) Includes three drillships under construction, as well as one operating drillship.
(d) Includes a rig to be constructed 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 principally determined by the length of the rig’s legs. The rig hull includes the drilling rig, 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. Most of Diamond Offshore’s jack-up rigs are equipped with a cantilever system that enables the rig to cantilever or 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 December of 2010, Diamond Offshore has entered into three separate turnkey contracts with Hyundai Heavy Industries Co. Ltd., for the construction of three dynamically positioned, ultra-deepwater drillships with deliveries scheduled for the second and fourth quarters of 2013 and the second quarter of 2014. Diamond Offshore expects the aggregate cost for the three drillships, including commissioning, spares and project management, to be approximately $1.8 billion.
During 2009, Diamond Offshore acquired two new-build ultra-deepwater, dynamically positioned, semisubmersible drilling rigs. Including Diamond Offshore’s rig acquisitions in 2009 and its three drillships on order, Diamond Offshore has purchased, ordered or upgraded eight rigs with capabilities in nominal water depths of 10,000 feet over the last five years.
In December of 2011, Diamond Offshore entered into an agreement for the construction of a moored semisubmersible rig, which will be designed to operate in water depths up to 6,000 feet. The rig will be constructed utilizing the hull of one of Diamond Offshore’s mid-water floaters that previously operated as the Ocean Voyager. The rig will be constructed in Brownsville, Texas and is expected to be delivered in the third quarter of 2013 at an aggregate cost of approximately $300 million, including commissioning, spares and project management costs.
Diamond Offshore will evaluate further rig acquisition and upgrade opportunities as they arise. However, Diamond Offshore can provide no assurance whether, or to what extent, it will continue to make rig acquisitions or upgrades to its fleet.
Markets: The principal markets for Diamond Offshore’s contract drilling services are the following:
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South America, principally offshore Brazil;
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Australia and Asia, including Malaysia, Indonesia, Thailand and Vietnam;
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the Middle East, including Kuwait, Qatar and Saudi Arabia;
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Europe, principally in the United Kingdom (“U.K.”) and Norway;
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East and West Africa;
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the Mediterranean Basin, including Egypt; and
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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 segment or area enables it to better understand that customer’s needs and better serve that customer in different market segments 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.
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 2011, 2010 and 2009, Diamond Offshore performed services for 52, 46 and 47 different customers. During 2011, 2010 and 2009, 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 35%, 24% and 15% of Diamond Offshore’s annual total consolidated revenues. OGX Petróleo e Gás Ltda., or (“OGX”), (a privately owned Brazilian oil and natural gas company), accounted for 14% of Diamond Offshore’s total consolidated revenues in each of the years ended December 31, 2011 and 2010. No other customer accounted for 10% or more of Diamond Offshore’s annual total consolidated revenues during 2011, 2010 or 2009.
Brazil is one of the most active floater markets in the world today. As of the date of this Report, the greatest concentration of Diamond Offshore’s operating assets is offshore Brazil, where it has 14 rigs currently working. Diamond Offshore’s contract backlog attributable to its expected operations offshore Brazil is $1.3 billion, $1.2 billion and $1.0 billion for the years 2012, 2013 and 2014, and $607 million in the aggregate for the years 2015 to 2016.
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. The offshore contract drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Some of Diamond Offshore’s competitors may have greater financial or other resources than Diamond Offshore. Diamond Offshore competes with offshore drilling contractors that together have almost 760 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.
Operations Outside the United States: Diamond Offshore’s operations outside the U.S. accounted for approximately 90.3%, 80.9% and 66.0% of its total consolidated revenues for the years ended December 31, 2011, 2010 and 2009.
Properties: Diamond Offshore owns an eight-story office building totaling 170,000 square feet on 6.2 acres of land located in Houston, Texas, where its corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for its offshore drilling warehouse and storage facility, a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for its North Sea operations, two buildings totaling 77,200 square feet and 11 acres of land in Macae, Brazil, for its South American operations and two buildings totaling 21,000 square feet and two acres of land in Ciudad del Carmen, Mexico, for its Mexican operations. Additionally, Diamond Offshore currently leases various office, warehouse and storage facilities in Louisiana, Australia, Indonesia, Norway, Malaysia, Singapore, Egypt, Equatorial Guinea, Angola, Vietnam and the U.K. to support its offshore drilling operations.
HIGHMOUNT EXPLORATION & PRODUCTION LLC
HighMount is engaged in the exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids (“NGLs”)). HighMount accounted for 2.5%, 2.9% and 4.4% of our consolidated total revenue for the years ended December 31, 2011, 2010 and 2009.
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 700,000 net acres in the Permian Basin, with over 6,000 producing wells.
In 2011, HighMount acquired working interests in undeveloped oil and gas properties located on approximately 74,000 net acres in Oklahoma and approximately 12,000 net acres in the Texas Panhandle. HighMount believes that these properties contain primarily oil and liquids reserves which can be produced through horizontal drilling.
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, working and other similar interests and contractual arrangements with other parties as is customary in the oil and gas industry. HighMount also owns and operates approximately 3,000 miles of gathering lines and over 75,000 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 mineral interest
Gross wells
-
Total number of wells in which HighMount owns a mineral 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 mineral interest owned by HighMount in such gross acreage
Net wells
-
The sum of all gross wells multiplied by the mineral 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
-
Leased acres 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, 2011, HighMount owned 1.1 Tcfe of net proved reserves, of which 75% were classified as proved developed reserves. HighMount’s estimated total proved reserves consist of 819.4 Bcf of natural gas, 48.3 MMBbls of NGLs, and 4.0 MMBbls of oil and condensate. HighMount produced approximately 173 MMcfe per day of net natural gas, NGLs and oil during 2011. 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 63 wells during 2011, of which 56 (or 88.9%) are productive wells.
Reserves: HighMount’s reserves represent its share of reserves based on its net revenue interest in each property. Estimated reserves as of December 31, 2011 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 28 years of oil and gas engineering experience in the reservoir discipline. He is a member in good standing of the Society of Petroleum Engineers.
HighMount’s reserves estimates for 2011 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.. The technical person primarily responsible for NSAI’s audit and audit letter has 31 years of industry experience and has been practicing consulting petroleum engineering at NSAI since 1989.
The following table sets forth HighMount’s proved reserves at December 31, 2011, based on average 2011 prices of $4.12 per MMBtu for natural gas, $55.18 per Bbl for NGLs and $96.19 per Bbl for oil. Substantially all proved reserves were located in the Permian Basin.
HighMount reviews its proved reserves on an annual basis. During 2011, total proved reserves declined 166 Bcfe, reflecting (i) a 151 Bcfe reduction as a result of recent higher decline rates of producing wells and economic factors such as lower gas prices and higher operating expenses, (ii) a 63 Bcfe reduction as a result of production during the year, offset by (iii) additions of 48 Bcfe through drilling and proven undeveloped locations.
At December 31, 2011, HighMount had proved undeveloped reserves of 283 Bcfe. During 2011, HighMount recorded negative net reserve revisions of 20 Bcfe primarily due to a reclassification of proved undeveloped reserves to the non-proved category because these reserves were no longer economical due to the decrease in natural gas prices. Also, 29 Bcfe of non-proved reserves were promoted to the proved undeveloped category as a result of the 2011 drilling activity and increased NGL and oil prices. During 2011, HighMount spent $25 million to convert 14 Bcfe from proved undeveloped reserves to proved developed reserves through drilling.
Estimated net quantities of proved natural gas and oil reserves at December 31, 2011, 2010 and 2009 and changes in the reserves during 2011, 2010 and 2009 are shown in Note 14 of the Notes to Consolidated Financial Statements included under Item 8.
HighMount’s properties typically have relatively long reserve lives, high well completion success rates and predictable production profiles. Based on December 31, 2011 proved reserves and HighMount’s average production from these properties during 2011, the average reserve-to-production index of HighMount’s proved reserves is 18 years.
In order to replenish reserves as they are depleted by production, and to increase reserves, HighMount develops its existing acreage by drilling new wells and, where available, employing new technologies and drilling strategies designed to enhance production from existing wells. In addition, HighMount seeks to acquire additional acreage in its core areas of operation, as well as other locations where its management has identified an opportunity. For example, in 2011, HighMount acquired acreage in the Mississippian Lime play in Oklahoma and the Anadarko Basin in the Texas Panhandle.
During 2011, 2010 and 2009, HighMount engaged in the drilling activity presented in the following table:
In addition, at December 31, 2011, HighMount had 30 (29.3 net) wells in progress.
Acreage: As of December 31, 2011, HighMount owned interests in developed and undeveloped acreage in the locations set forth in the table below:
(a) Represents acreage in Oklahoma and the Texas Panhandle.
As of December 31, 2011, leases covering 45,256, 41,505 and 24,425 of HighMount’s net acreage will expire by December 31, 2012, 2013 and 2014, if production is not established or HighMount takes no other action to extend the terms.
Production and Sales: Please see the Production and Sales statistics table for additional information included in the MD&A under Item 7.
HighMount utilizes its own marketing and sales personnel to market the natural gas and oil that it produces to large energy companies and intrastate pipelines and gathering companies. Production is typically sold and delivered directly to a pipeline at liquid pooling points or at the tailgates of various processing plants, where it then enters a pipeline system. Permian Basin natural gas sales prices are primarily at a Houston Ship Channel Index.
To manage the risk of fluctuations in prevailing commodity prices, HighMount enters into commodity and basis swaps and other derivative instruments.
Wells: As of December 31, 2011, HighMount had an interest in 6,352 gross producing wells (5,839 net producing wells) located primarily in the Permian Basin. Wells located in the Permian Basin have a typical well depth in the range of 6,000 to 9,000 feet.
Competition: HighMount competes with other oil and gas companies in all aspects of its business, including acquisition of producing properties and leases and obtaining goods, services and labor, including drilling rigs and well completion services. HighMount also competes in the marketing of produced natural gas and oil. Some of HighMount’s competitors have substantially larger financial and other resources than HighMount. Factors that affect HighMount’s ability to acquire producing properties include available funds, available information about the property and standards established by HighMount for minimum projected return on investment. Natural gas and oil also compete with alternative fuel sources, including heating oil and coal.
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; and 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 properties; maximum rates of production from wells; venting or flaring of natural gas and the ratability of production.
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. 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; however, it 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 Natural Gas Act (“NGA”) to prohibit natural gas market manipulation by any entity, directed the Federal Energy Regulatory Commission (“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 NGA 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 U.S. Department of Transportation (“DOT”) and state agencies with respect to safety and operating conditions.
HighMount’s operations are also subject to federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, HighMount’s operations may require it to obtain permits for, among other things, air emissions, discharges into surface waters, and the construction and operation of underground injection wells or surface pits to dispose of produced saltwater and other non-hazardous oilfield wastes. HighMount could be required, without regard to fault or the legality of the original disposal, to remove or remediate previously disposed wastes, to suspend or cease operations in contaminated areas or to perform remedial well plugging operations or cleanups to prevent future contamination.
In September of 2009, the United States Environmental Protection Agency (“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 beginning in March of 2011. Oil and gas exploration and production companies that emit less than 25,000 metric tons of GHG per year from any facility (as defined in the regulations), including HighMount, are not required to monitor or report emissions at this time. However, the EPA has indicated it will issue a proposed rule for comment as it pertains to oil and gas systems.
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 92,000 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.
BOARDWALK PIPELINE PARTNERS, LP
Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”) is engaged in the interstate transportation and storage of natural gas. Boardwalk Pipeline accounted for 8.1%, 7.7% and 6.4% of our consolidated total revenue for the years ended December 31, 2011, 2010 and 2009.
We own approximately 61% of Boardwalk Pipeline comprised of 102,719,466 common units, 22,866,667 class B units and a 2% general partner interest. A wholly owned subsidiary of ours, Boardwalk Pipelines Holding Corp. (“BPHC”) is the general partner and holds all of Boardwalk Pipeline’s incentive distribution rights which entitle the general partner to an increasing percentage of the cash that is distributed by Boardwalk Pipeline in excess of $0.4025 per unit per quarter.
Boardwalk Pipeline owns and operates three interstate natural gas pipelines, with approximately 14,200 miles of interconnected pipelines, directly serving customers in 12 states and indirectly serving customers throughout the northeastern and southeastern United States through numerous interconnections with unaffiliated pipelines. In 2011, its pipeline systems transported approximately 2.7 Tcf of gas. Average daily throughput on Boardwalk Pipeline’s pipeline systems during 2011 was approximately 7.3 Bcf. Boardwalk Pipeline’s natural gas storage facilities are comprised of 11 underground storage fields located in four states with aggregate working gas capacity of approximately 167 Bcf.
Boardwalk Pipeline serves a broad mix of customers, including producers, local distribution companies, marketers, electric power generators, direct industrial users and interstate and intrastate pipelines located throughout the Gulf Coast, Midwest and Northeast regions of the U.S.
In December of 2011, Boardwalk HP Storage Company, LLC (“HP Storage”), a joint venture between Boardwalk Pipeline and BPHC, acquired seven salt dome natural gas storage caverns and associated assets in Mississippi for approximately $550 million. HP Storage funded the acquisition with proceeds from a $200 million five year variable rate term loan and equity contributions from BPHC and Boardwalk Pipeline. BPHC contributed $280 million for an 80% interest in HP Storage and Boardwalk Pipeline contributed $70 million for a 20% interest. Boardwalk Pipeline operates the assets of HP Storage on behalf of the joint venture.
The pipeline 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, 2011 was 1.2 Bcf per day.
The Gulf South pipeline system runs approximately 7,600 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, 2011 was 4.3 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, 2011 was 3.2 Bcf per day. Texas Gas owns nine natural gas storage fields with 84.0 Bcf of working gas storage capacity.
Boardwalk Pipeline’s current expansion projects include the following:
South Texas Eagle Ford Expansion: The South Texas Eagle Ford Expansion construction project consists of 55 miles of gathering pipeline and a cryogenic processing plant. The system will have the capability of gathering in excess of 0.3 Bcf per day of liquids rich gas in the Eagle Ford Shale production area in Texas and processing up to 150 MMcf per day of wet gas. Boardwalk Pipeline will also provide re-delivery of processed residue gas to a number of interstate and intrastate pipelines. Boardwalk Pipeline has executed long term fee-based gathering and processing agreements for approximately 50% of the plant’s processing capacity. The plant and new pipeline are estimated to cost approximately $180 million and are expected to be placed in service in early 2013.
Marcellus Gathering System: The Marcellus Gathering System is part of a 15 year definitive gas gathering agreement between Boardwalk Pipeline and Southwestern Energy Production Company (“Southwestern”) which will require construction of a natural gas gathering system in Pennsylvania. Boardwalk Pipeline will own the gas gathering system that will support Southwestern’s development of Marcellus Shale gas. The gathering system is expected to have a delivery capacity of approximately 0.3 Bcf per day when fully constructed and the first portion of the system is expected to be placed in service in April of 2012. The project is expected to cost approximately $90 million.
HP Storage: HP Storage is in the process of leaching a new salt dome storage cavern which is expected to have working gas capacity of approximately 5.0 Bcf. The additional capacity is expected to be placed in service in the first quarter of 2013 with an estimated cost of approximately $35 million.
Competition: Boardwalk Pipeline competes with numerous other pipelines that provide natural gas transportation and storage services at many locations along its pipeline systems. Boardwalk Pipeline also competes with pipelines that are attached to new gas supply sources that are being developed closer to some of its traditional market areas and that customers can access through third party pipelines. 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 the regulators’ policies, segmentation and capacity release have created an active secondary market which increasingly competes with Boardwalk Pipeline’s 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 other than pricing, 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 and natural gas price levels and 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 2011, 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 operating subsidiaries under the NGA of 1938 and the NGA 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 operating 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 for all aspects of the gas transportation services it provides are established through FERC’s cost-of-service rate-making process. The maximum rates that may be charged by Boardwalk Pipeline for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized Gulf South to charge market-based rates for its firm and interruptible storage. Texas Gas is authorized to charge market-based rates for the firm and interruptible storage services associated with approximately 8.3 Bcf of its storage capacity. Neither Gulf South nor Texas Gas has an obligation to file a new rate case. In January of 2012, Gulf Crossing filed with FERC a cost-and-revenue study to justify its rates as mandated in the initial order approving the construction and operation of that pipeline. Although FERC could open a proceeding under Section 5 of the Natural Gas Act to review rates in response to the filing, the outcome of this filing is not expected to have a material impact on Boardwalk Pipeline’s business, financial condition, results of operations or cash flows.
Boardwalk Pipeline is also regulated by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas pipelines. Boardwalk Pipeline has received authority from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of DOT, to operate certain 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 pipelines at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along their pipelines and take additional measures to protect pipeline segments located in highly populated areas. A recently enacted pipeline safety bill could result in increased regulatory requirements.
Boardwalk Pipeline’s operations are also subject to extensive federal, state, and local laws and regulations relating to protection of the environment. Such regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental regulations also require that Boardwalk Pipeline’s facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.
Properties: Boardwalk Pipeline is headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. Boardwalk Pipeline also has approximately 108,000 square feet of office space in Owensboro, Kentucky in a building that it owns. 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.
LOEWS HOTELS HOLDING CORPORATION
The subsidiaries of Loews Hotels Holding Corporation (“Loews Hotels”), our wholly owned subsidiary, presently operate the following 17 hotels. Loews Hotels accounted for 2.4%, 2.1% and 2.0% of our consolidated total revenue for the years ended December 31, 2011, 2010 and 2009.
Name and Location
Number of
Rooms
Owned, Leased or Managed
Loews Annapolis Hotel
Annapolis, Maryland
Owned
Loews Atlanta Hotel
Atlanta, Georgia
Management contract
Loews Coronado Bay
San Diego, California
Land lease expiring 2034
Loews Denver Hotel
Denver, Colorado
Owned
The Don CeSar, a Loews Hotel
St. Pete Beach, Florida
Management contract (a)
Hard Rock Hotel,
at Universal Orlando
Orlando, Florida
Management contract (b)
Loews Le Concorde Hotel
Quebec City, Canada
Land lease expiring 2069
Loews Miami Beach Hotel
Miami Beach, Florida
Owned
Loews New Orleans Hotel
New Orleans, Louisiana
Management contract
Loews Philadelphia Hotel
Philadelphia, Pennsylvania
Owned
Loews Portofino Bay Hotel,
at Universal Orlando
Orlando, Florida
Management contract (b)
Loews Regency Hotel
New York, New York
Land lease expiring 2036, with renewal option for 24 years
Loews Royal Pacific Resort
1,000
Management contract (b)
at Universal Orlando
Orlando, Florida
Loews Santa Monica Beach Hotel
Santa Monica, California
Management contract, with renewal option for 5 years
Loews Vanderbilt Hotel
Owned
Nashville, Tennessee
Loews Ventana Canyon
Management contract
Tucson, Arizona
Loews Hotel Vogue
Owned
Montreal, Canada
(a) A Loews Hotels subsidiary is a 20% owner of the hotel, which is being operated by Loews Hotels pursuant to a management contract.
(b) A Loews Hotels subsidiary is a 50% owner of these hotels located at the Universal Orlando theme park, through a joint venture. The hotels are on land leased by the joint venture and are operated by Loews Hotels pursuant to a management contract.
The hotels owned by Loews Hotels are subject to mortgage indebtedness totaling approximately $213 million at December 31, 2011 with interest rates ranging from 1.7% to 6.3%, and maturing between 2012 and 2028. In addition, certain hotels are held under leases which are subject to formula derived rental increases, with rentals aggregating approximately $7 million for the year ended December 31, 2011.
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 18,250 persons at December 31, 2011. We, and our subsidiaries, have experienced satisfactory labor relations.
CNA employed approximately 7,600 persons.
Diamond Offshore employed approximately 5,300 persons, including international crew personnel furnished through independent labor contractors.
HighMount employed approximately 400 persons.
Boardwalk Pipeline employed approximately 1,170 persons, approximately 115 of whom are union members covered under collective bargaining units.
Loews Hotels employed approximately 3,500 persons, approximately 780 of whom are union members covered under collective bargaining units.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Position and Offices Held
Age
First
Became
Officer
David B. Edelson
Senior Vice President
Gary W. Garson
Senior Vice President, General Counsel and Secretary
Herbert C. Hofmann
Senior Vice President
Peter W. Keegan
Senior Vice President and Chief Financial Officer
Richard W. Scott
Senior Vice President and Chief Investment Officer
Kenneth I. Siegel
Senior Vice President
Andrew H. Tisch
Office of the President, Co-Chairman of the Board and Chairman of the Executive Committee
James S. Tisch
Office of the President, President and Chief Executive Officer
Jonathan M. Tisch
Office of the President and Co-Chairman of the Board
Andrew H. Tisch and James S. Tisch are brothers and are cousins of Jonathan M. Tisch. None of the other officers or directors of Registrant is related to any other.
All of our executive officers except for Kenneth I. Siegel and Richard W. Scott have been engaged actively and continuously in our business for more than the past five years. Prior to joining us in 2009, Mr. Siegel was employed as a Managing Director in the Mergers & Acquisitions Department at Barclays Capital Inc. and previously in a similar capacity at Lehman Brothers. Prior to joining us in 2009, Mr. Scott was employed at American International Group, Inc. for more than five years, serving in various senior investment positions, including Chief Investment Officer-Insurance Portfolio Management.
Officers are elected and hold office until their successors are elected and qualified, and are subject to removal by the Board of Directors.
AVAILABLE INFORMATION
Our website address is www.loews.com. We make available, free of charge, through the website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after these reports are electronically filed with or furnished to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee charter, Compensation Committee charter and Nominating and Governance Committee charter have also been posted and are available on our website.
Item 1A. RISK FACTORS.
Our business faces many risks. We have described below some of the more significant risks which we and our subsidiaries face. There may be additional risks that we do not yet know of or that we do not currently perceive to be significant that may also impact our business or the business of our subsidiaries.
Each of the risks and uncertainties described below could lead to events or circumstances that have a material adverse effect on our business, results of operations, cash flows, financial condition or equity and/or the business, results of operations, financial condition or equity of one or more of our subsidiaries.
You should carefully consider and evaluate all of the information included in this Report and any subsequent reports we may file with the SEC or make available to the public before investing in any securities issued by us. Our subsidiaries, CNA Financial Corporation, Diamond Offshore Drilling, Inc. and Boardwalk Pipeline Partners, LP, are public companies and file reports with the SEC. You are also cautioned to carefully review and consider the information contained in the reports filed by those subsidiaries before investing in any of their securities.
Risks Related to Us and Our Subsidiary, CNA Financial Corporation
If CNA determines that its recorded insurance reserves are insufficient to cover its estimated ultimate unpaid liability for claims and claim adjustment expense, CNA may need to increase its insurance reserves.
CNA maintains insurance reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for reported and unreported claims and for future policy benefits. Reserves represent CNA’s best estimate at a given point in time. Insurance reserves are not an exact calculation of liability but instead are complex estimates derived by CNA, generally utilizing a variety of reserve estimation techniques from numerous assumptions and expectations about future events, many of which are highly uncertain, such as estimates of claims severity, frequency of claims, mortality, morbidity, discount rates, inflation, claims handling, case reserving policies and procedures, underwriting and pricing policies, changes in the legal and regulatory environment and the lag time between the occurrence of an insured event and the time of its ultimate settlement. Mortality is the relative incidence of death. Morbidity is the frequency and severity of illness, sickness and diseases contracted. Many of these uncertainties are not precisely quantifiable and require significant judgment on CNA’s part. As trends in underlying claims develop, particularly in so-called “long tail” or long duration coverages, CNA is sometimes required to add to its reserves. This is called unfavorable net prior year 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 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 which can have a material adverse effect on its results of operations and equity. The effects of these and other unforeseen emerging claim and coverage issues are extremely hard to predict. Examples of emerging or potential claims and coverage issues include:
•
the effects of worldwide economic conditions, which have resulted in an increase in the number and size of certain claims including both directors and officers (“D&O”) and errors and omissions (“E&O”) insurance claims related to corporate failures, as well as other coverages;
•
class action litigation relating to claims handling and other practices; and
•
mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals, and various other chemical and radiation exposure claims.
In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews and changes its reserve estimates in a regular and ongoing process as experience develops and further claims are reported and settled. If estimated reserves are insufficient for any reason, the required increase in reserves would be recorded as a charge against earnings in the period in which reserves are determined to be insufficient. These charges could be substantial.
Catastrophe losses are unpredictable and could result in material losses.
Catastrophe losses are an inevitable part of CNA’s business. Various events can cause catastrophe losses. These events can be natural or man-made, and may include hurricanes, windstorms, earthquakes, hail, severe winter weather, fires, and acts of terrorism. The frequency and severity of these catastrophe events are inherently unpredictable. In addition, longer-term natural catastrophe trends may be changing and new types of catastrophe losses may be developing due to climate change, a phenomenon that has been associated with extreme weather events linked to rising temperatures, and includes effects on global weather patterns, greenhouse gases, sea, land and air temperatures, sea levels, rain 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, and the level of reinsurance 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, losses from these types of catastrophe losses are particularly difficult to manage.
As CNA’s claim experience develops on a specific catastrophe, CNA may be required to adjust its reserves, or take unfavorable net prior year development, to reflect revised estimates of the total cost of claims.
CNA’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.
CNA has significant amounts recoverable from reinsurers which are reported as receivables in 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. Certain of CNA’s reinsurance carriers have experienced deteriorating financial condition or have been downgraded by rating agencies. In addition, reinsurers could dispute amounts which CNA believes are due to it. If CNA is not able to collect the amounts due from reinsurers, its net incurred losses will be higher.
CNA has exposure related to asbestos and environmental pollution (“A&EP”) claims, which could result in additional 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 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 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 key assumptions used to determine reserves and the recoverability of deferred acquisition costs for long term care products and payout annuity contracts could vary significantly from actual experience.
CNA’s reserves and the recoverability of deferred acquisition costs for long term care products and payout annuity contracts are based on certain key assumptions including: (i) morbidity; (ii) mortality; (iii) policy persistency, which is the percentage of policies remaining in force; and (iv) discount rates, which are impacted by expected investment yields. These foregoing assumptions, while based on historical data and industry experience, and monitored consistently, are critical bases for reserve estimates. Accordingly, if actual experience differs from these assumptions, the deferred acquisition cost asset may not be fully realized and CNA’s reserves may not be adequate, requiring CNA to add to reserves. Any such adjustments to reserves would be reflected in the Consolidated Statements of Income in the period the need for such adjustment is determined.
CNA is exposed to credit risk under deductible policies.
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 has incurred and may continue to incur significant realized and unrealized investment losses and volatility in net investment income arising from volatility in the capital and credit markets.
CNA’s investment portfolio is exposed to various risks, such as interest rate, credit and currency risks, many of which are unpredictable. Investment returns are an important part of CNA’s overall profitability. General economic conditions, changes in financial markets such as fluctuations in interest rates, credit conditions and currency, commodity and stock prices, and many other factors beyond CNA’s control can adversely affect the value of its investments and the realization of investment income. Further, CNA invests a portion of its assets in equity securities and limited partnerships which are subject to greater market volatility than its fixed income investments. In addition, limited partnership investments generally present, higher illiquidity than fixed income investments. As a result of all of these factors, CNA may not realize an adequate return on its investments, may incur losses on sales of its investments, and may be required to write-down the value of its investments.
CNA’s valuation of investments and impairment of securities requires significant judgment.
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. 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 types of risks and the resulting 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 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, regulators may restrict or prohibit it from operating its business. If CNA is required to record a material charge against earnings in connection with a change in estimates or circumstances or if it incurs significant unrealized losses related to its investment portfolio, CNA may violate these minimum capital adequacy requirements unless it is able to raise sufficient additional capital.
While we have provided CNA with substantial amounts of capital in prior years, we may be restricted in our ability or may not be willing to provide additional capital support to CNA in the future. If CNA is in need of additional capital, CNA may be required to secure this funding from sources other than us. CNA may be limited in its ability to raise significant amounts of capital on favorable terms or at all.
CNA’s insurance subsidiaries, upon whom CNA depends for dividends in order to fund its working capital needs, are limited by state 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 state departments of insurance are generally limited to amounts determined by formula which varies by state. The formula for the majority of the 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 states, however, have an additional stipulation that dividends cannot exceed the prior year’s earned surplus. If CNA is restricted, by regulatory rule or otherwise, from paying or receiving inter-company dividends, CNA may not be able to fund its working capital needs and debt service requirements from available cash. As a result, CNA would need to look to other sources of capital which may be more expensive or may not be available at all.
Rating agencies may downgrade their ratings of CNA and thereby adversely affect its ability to write insurance at competitive rates or at all.
Ratings are an important factor in establishing the competitive position of insurance companies. CNA’s insurance company subsidiaries, as well as CNA’s public debt, are rated by rating agencies, namely, A.M. Best Company (“A.M. Best”), Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s (“S&P”). Ratings reflect the rating agency’s opinions of an insurance company’s or insurance holding company’s financial strength, capital adequacy, operating performance, strategic position and ability to meet its obligations to policyholders and debt holders.
Due to the intense competitive environment in which CNA operates, the uncertainty in determining reserves and the potential for CNA to take material unfavorable net prior year development in the future, and possible changes in the methodology or criteria applied by the rating agencies, the rating agencies may take action to lower CNA’s ratings in the future. If CNA’s property and casualty insurance financial strength ratings are downgraded below current levels, CNA’s business and results of operations could be materially adversely affected. The severity of the impact on CNA’s business is dependent on the level of downgrade and, for certain products, which rating agency takes the rating action. Among the adverse effects in the event of such downgrades would be the inability to obtain a material volume of business from certain major insurance brokers, the inability to sell a material volume of CNA’s insurance products to certain markets, and the required collateralization of certain future payment obligations or reserves.
In addition, it is possible that a lowering of our corporate debt ratings by certain of the rating agencies could result in an adverse impact on CNA’s ratings, independent of any change in CNA’s circumstances. CNA has entered into several settlement agreements and assumed reinsurance contracts that require collateralization of future payment obligations and assumed reserves if its ratings or other specific criteria fall below certain thresholds. The ratings triggers are generally more than one level below CNA’s current ratings.
Risks Related to Us and Our Subsidiary, Diamond Offshore Drilling, Inc.
Diamond Offshore’s business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.
Diamond Offshore’s business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since Diamond Offshore’s customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for Diamond Offshore’s rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond Diamond Offshore’s control, including:
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worldwide demand for oil and gas;
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the level of economic activity in energy-consuming markets;
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the worldwide economic environment or economic trends, such as recessions;
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the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing;
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the level of production in non-OPEC countries;
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the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;
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civil unrest;
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the cost of exploring for, producing and delivering oil and gas;
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the discovery rate of new oil and gas reserves;
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the rate of decline of existing and new oil and gas reserves;
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available pipeline and other oil and gas transportation and refining capacity;
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the ability of oil and gas companies to raise capital;
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weather conditions in the United States and elsewhere;
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natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;
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the policies of various governments regarding exploration and development of their oil and gas reserves;
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development and exploitation of alternative fuels or energy sources;
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competition for customers’ drilling budgets from land-based energy markets around the world;
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domestic and foreign tax policy; and
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advances in exploration and development technology.
Diamond Offshore’s business involves numerous operating hazards which could expose it to significant losses and significant damage claims. Diamond Offshore is not fully insured against all of these risks and its contractual indemnity provisions may not fully protect Diamond Offshore.
Diamond Offshore’s operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages.
Consistent with industry practice, Diamond Offshore’s contracts with its customers generally contain contractual rights to indemnity from its customer for, among other things, pollution originating from the well, while Diamond Offshore retains responsibility for pollution originating from the rig. However, Diamond Offshore’s contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by itself, its subcontractors and/or suppliers and Diamond Offshore’s customers may dispute, or be unable to meet, their contractual indemnification obligations.
Diamond Offshore maintains liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, Diamond Offshore’s insurance coverage may not adequately cover its losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, Diamond Offshore does not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Moreover, insurance costs across the industry have increased following the Macondo incident and, in the future, certain insurance coverage is likely to become more costly and may become less available or not available at all.
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 our results of operations, financial position and cash flows. There can be no assurance that Diamond Offshore will continue to carry the insurance it currently maintains, that its insurance will cover all types of losses or that those parties with contractual obligations to indemnify Diamond Offshore will necessarily be financially able to indemnify Diamond Offshore against all of these risks. In addition, no assurance can be made that Diamond Offshore will be able to maintain adequate insurance in the future at rates it considers to be reasonable or that Diamond Offshore will be able to obtain insurance against some risks.
Diamond Offshore’s industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of Diamond Offshore’s competitors may have greater financial or other resources than it does. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Price is typically the primary factor in determining which qualified contractor is awarded a job; however, rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered.
Diamond Offshore’s industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. Diamond Offshore cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. In response to a contraction in demand for certain types of its drilling rigs, primarily shallow water jack-up rigs, Diamond Offshore has cold stacked eight rigs as of the date of this Report. Diamond Offshore also may be required to idle additional rigs or to enter into lower rate contracts. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of Diamond Offshore’s drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
Significant new rig construction and upgrades of existing drilling rigs could also intensify price competition. Based on analyst reports, Diamond Offshore believes that there are approximately 77 jack-up rigs and 96 floaters on order and scheduled for delivery between 2012 and 2018, with approximately half of these rigs scheduled for delivery in the next two years. 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 35% of Diamond Offshore’s consolidated revenues in 2011 and, as of February 1, 2012, accounted for approximately $3.7 billion of contract drilling backlog through 2016 and to which ten of Diamond Offshore’s floaters are currently contracted, has announced plans to construct locally 33 new deepwater drilling rigs to be delivered beginning in 2015. These new drilling rigs would increase rig supply and could intensify price competition in Brazil as well as other markets as they enter the market, would compete with, and could displace, Diamond Offshore’s deepwater and ultra-deepwater floaters coming off contract and could materially adversely affect Diamond Offshore’s utilization rates, particularly in Brazil.
Diamond Offshore can provide no assurance that its current backlog of contract drilling revenue will be ultimately realized.
As of February 1, 2012, Diamond Offshore’s contract drilling backlog was approximately $8.6 billion for contracted future work extending, in some cases, until 2019. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, Diamond Offshore may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. Diamond Offshore can provide no assurance that it will be able to perform under these contracts due to events beyond its control or that Diamond Offshore will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, Diamond Offshore can provide no assurance that its customers will be able to or 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 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 2011, Diamond Offshore’s five largest customers in the aggregate accounted for 62% of its consolidated revenues. Diamond Offshore expects Petrobras and OGX, which accounted for approximately 35% and 14% of Diamond Offshore’s consolidated revenues in 2011, to continue to be significant customers in 2012. Diamond Offshore’s contract drilling backlog, as of the date of this Report, includes $1.3 billion, or 51% of its contracted backlog for 2012, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil. While it is normal for Diamond Offshore’s customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on Diamond Offshore’s business.
The terms of Diamond Offshore’s drilling contracts may limit its ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market.
The duration of offshore drilling contracts is generally determined by customer requirements and, to a lesser extent, the respective management strategies of the offshore drilling contractors. In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit Diamond Offshore’s profitability.
Contracts for Diamond Offshore’s drilling rigs are generally fixed dayrate contracts, and increases in Diamond Offshore’s operating costs could adversely affect the profitability on those contracts.
Diamond Offshore’s contracts for its drilling rigs provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by Diamond Offshore. Many of Diamond Offshore’s operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond Diamond Offshore’s control. The gross margin that Diamond Offshore realizes on these fixed dayrate contracts will fluctuate based on variations in Diamond Offshore’s operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, Diamond Offshore may be unable to recover increased or unforeseen costs from its customers.
Diamond Offshore’s drilling contracts may be terminated due to events beyond its control.
Diamond Offshore’s customers may terminate some of their term drilling contracts if the drilling rig is destroyed or lost or if Diamond Offshore has to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of Diamond Offshore’s drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. During periods of depressed market conditions, Diamond Offshore may be subject to an increased risk of its customers seeking to repudiate their contracts. Diamond Offshore’s customers’ ability to perform their obligations under drilling contracts may also be adversely affected by restricted credit markets and the economic downturn.
A significant portion 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 that may expose it to political and other uncertainties, including risks of:
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terrorist acts, war and civil disturbances;
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piracy or assaults on property or personnel;
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kidnapping of personnel;
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expropriation of property or equipment;
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renegotiation or nullification of existing contracts;
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changing political conditions;
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foreign and domestic monetary policies;
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the inability to repatriate income or capital;
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difficulties in collecting accounts receivable and longer collection periods;
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fluctuations in currency exchange rates;
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regulatory or financial requirements to comply with foreign bureaucratic actions;
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travel limitations or operational problems caused by public health threats; and
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changing taxation policies.
Diamond Offshore is subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing its international operations in addition to worldwide anti-bribery laws. In addition, international contract drilling operations are subject to various laws and regulations in countries in which Diamond Offshore operates, including laws and regulations relating to:
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the equipping and operation of drilling rigs;
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import - export quotas or other trade barriers;
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repatriation of foreign earnings or capital;
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oil and gas exploration and development;
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taxation of offshore earnings and earnings of expatriate personnel; and
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use and compensation of local employees and suppliers by foreign contractors.
Some foreign governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect Diamond Offshore’s ability to compete in those regions. It is difficult to predict what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments may materially and adversely affect Diamond Offshore’s ability to compete.
In addition, the shipment of goods, including the movement of a drilling rig across international borders, subjects Diamond Offshore to extensive trade laws and regulations. Diamond Offshore’s import activities are governed by unique customs laws and regulations that differ in each of the countries in which Diamond Offshore operates and often impose record keeping and reporting obligations. The laws and regulations concerning import/export activity and record keeping and reporting requirements are complex and change frequently. These laws and regulations may be enacted, amended enforced and/or interpreted in a manner that could materially and adversely impact Diamond Offshore’s operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which may be outside of Diamond Offshore’s control. Shipping delays or denials could cause unscheduled downtime for rigs. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to Diamond Offshore, among other things.
As of the date of this Report, the greatest concentration of Diamond Offshore’s operating assets outside the United States was offshore Brazil, where it has 14 rigs in its fleet either currently working or contracted to work during 2012.
Diamond Offshore may enter into drilling contracts that exposes it to greater risks than it normally assumes.
From time to time, Diamond Offshore may enter into drilling contracts with national oil companies, government-controlled entities or others that expose it to greater risks than it normally assumes, such as exposure to greater environmental or other liability and more onerous termination provisions giving the customer a right to terminate without
cause or upon little or no notice. Upon termination, these contracts may not result in a payment to Diamond Offshore, or if a termination payment is required, it may not fully compensate Diamond Offshore for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time. For example, Diamond Offshore currently operates, and expects to continue to operate, its drilling rigs offshore Mexico for PEMEX - Exploración y Producción (“PEMEX”), the national oil company of Mexico. The terms of these contracts expose Diamond Offshore to greater environmental liability than it normally assumes, and provide that, among other things, each contract can be terminated by PEMEX on short notice, contractually or by statute, subject to certain conditions. While Diamond Offshore believes that the financial terms of these contracts and its operating safeguards in place mitigate these risks, it can provide no assurance that the increased risk exposure will not have a material negative impact on future operations or financial results.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses.
Due to Diamond Offshore’s international operations, Diamond Offshore may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where it does not effectively hedge an exposure to a foreign currency. Diamond Offshore may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. Diamond Offshore can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.
Diamond Offshore may be required to accrue additional tax liability on certain of its foreign earnings.
Certain of Diamond Offshore’s international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited (“DOIL”), a wholly owned Cayman Islands subsidiary of Diamond Offshore. It is Diamond Offshore’s intention to indefinitely reinvest future earnings of DOIL and its foreign subsidiaries to finance foreign activities. Diamond Offshore does not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax. Should a future distribution be made from any unremitted earnings of this subsidiary, Diamond Offshore may be required to record additional U.S. income taxes.
Rig conversions, upgrades or new builds may be subject to delays and cost overruns.
From time to time, Diamond Offshore may undertake to add new capacity through conversions or upgrades to existing rigs or through new construction, such as its three new, ultra-deepwater drillships under construction and its construction of the Ocean Onyx. Projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:
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shortages of equipment, materials or skilled labor;
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work stoppages;
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unscheduled delays in the delivery of ordered materials and equipment;
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unanticipated cost increases;
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weather interferences;
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difficulties in obtaining necessary permits or in meeting permit conditions;
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design and engineering problems;
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customer acceptance delays;
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shipyard failures or unavailability; and
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failure or delay of third party service providers and labor disputes.
Failure to complete a rig upgrade or new construction on time, or failure to complete a rig conversion or new construction in accordance with its design specifications may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting in a loss of contract drilling backlog and revenue to Diamond Offshore. If a drilling contract is terminated under these circumstances, Diamond Offshore may not be able to secure a replacement contract with equally favorable terms.
Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM.
Because the amount of insurance coverage available to Diamond Offshore has been limited, and the cost for such coverage is substantial, Diamond Offshore has elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the GOM. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts.
Risks Related to Us and Our Subsidiary, HighMount Exploration & Production LLC
HighMount may not be able to replace reserves and sustain production at current levels. Replacing reserves is risky and uncertain and requires significant capital expenditures.
HighMount’s success depends largely upon its ability to find, develop or acquire additional reserves that are economically recoverable. Unless HighMount replaces the reserves produced through successful development, exploration or acquisition, its proved reserves will decline over time. HighMount may not be able to successfully find and produce reserves economically in the future or to acquire proved reserves at acceptable costs. HighMount makes a substantial amount of capital expenditures for the acquisition, exploration and development of reserves. HighMount expects to fund its capital expenditures with cash from its operating activities. If HighMount’s cash flow from operations is not sufficient to fund its capital expenditure budget, there can be no assurance that financing will be available or available at favorable terms to meet those requirements.
Estimates of natural gas and oil reserves are uncertain and inherently imprecise.
Estimating the volume of proved natural gas and oil reserves is a complex process and is not an exact science because of numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, these estimates are inherently imprecise.
Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves most likely will vary from HighMount’s estimates. Any significant variance could materially affect the quantities and present value of HighMount’s reserves. In addition, HighMount may adjust estimates of proved reserves upward or downward to reflect production history, results of exploration and development drilling, prevailing commodity prices and prevailing development expenses.
The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate representation of their value.
If commodity prices remain depressed, HighMount may be required to take additional write-downs of the carrying values of its properties.
HighMount may be required, under full cost accounting rules, to write-down the carrying value of its natural gas and oil properties. A number of factors could result in a write-down, including continued low commodity prices, a substantial downward adjustment to estimated proved reserves, a substantial increase in estimated development costs, or deterioration in exploration results. It is difficult to predict future changes in gas prices. However, the abundance of natural gas supply discoveries over the last few years would generally indicate a bias toward downward pressure on
prices. HighMount utilizes the full cost method of accounting for its exploration and development activities. Under full cost accounting, HighMount is required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of 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. A write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Depending on the magnitude of any future impairment, a ceiling test write-down could significantly reduce HighMount’s income, or produce a loss.
Natural gas, oil and other commodity prices are volatile.
The commodity price HighMount receives for its production heavily influences its revenue, profitability, access to capital and future rate of growth. If the current low price environment for natural gas continues, HighMount’s results of operations will be lower as well. HighMount is subject to risks due to frequent and possibly substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and HighMount expects this volatility to continue. The markets and prices for natural gas and oil depend upon factors beyond HighMount’s control. These factors include, among others, economic and market conditions, domestic production and import levels, storage levels, basis differentials, weather, government regulations and taxation. Lower commodity prices may reduce the amount of natural gas and oil that HighMount can produce economically.
HighMount engages in commodity price hedging activities.
The extent of HighMount’s commodity price risk is related to the effectiveness and scope of HighMount’s hedging activities. To the extent HighMount hedges its commodity price risk, HighMount will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor. Furthermore, because HighMount has entered into derivative transactions related to only a portion of its natural gas and oil production, HighMount will continue to have direct commodity price risk on the unhedged portion. HighMount’s actual future production may be significantly higher or lower than HighMount estimates at the time it enters into derivative transactions for that period.
As a result, HighMount’s hedging activities may not be as effective as HighMount intends in reducing the volatility of its cash flows, and in certain circumstances may actually increase the volatility of cash flows. In addition, even though HighMount’s management monitors its hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement or if the hedging arrangement is imperfect or ineffective.
Risks Related to Us and Our Subsidiary, Boardwalk Pipeline Partners, LP
Boardwalk Pipeline may not be able to maintain or replace expiring gas transportation and storage contracts at attractive rates or on a long term basis.
Boardwalk Pipeline is exposed to market risk when its transportation contracts expire and need to be renewed or replaced. Boardwalk Pipeline may not be able to extend contracts with existing customers or obtain replacement contracts at attractive rates or on a long term basis. Key drivers that influence the rates and terms of Boardwalk Pipeline’s transportation contracts include the current and anticipated basis differentials between physical locations on its pipeline systems, which can be affected by, among other things, the availability and supply of natural gas, competition from other pipelines, including pipelines under development, available capacity, storage inventories, regulatory developments, weather and general market demand in the respective areas. The new sources of natural gas that have been identified throughout the U.S. have created changes in pricing dynamics between supply basins, pooling points and market areas. As a result of the increase in overall pipeline capacity and the new sources of supply, basis spreads on Boardwalk Pipeline’s pipeline systems have narrowed over the past several years. Basis spreads have impacted, and will
continue to impact, the rates Boardwalk Pipeline can negotiate with its customers on contracts due for renewal for firm transportation services, especially the rates it can charge for interruptible and short term firm transportation services.
Boardwalk Pipeline needs to maintain authority from PHMSA to operate portions of its pipeline systems at higher than normal operating pressures.
Boardwalk Pipeline has entered into firm transportation contracts with shippers which utilize the design capacity of certain of its pipeline assets, assuming that Boardwalk Pipeline operates those pipeline assets at higher than normal operating pressures (up to 0.80 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 FERC’s rate-making policies which could limit Boardwalk Pipeline’s ability to recover the full cost of operating its pipelines, including earning a reasonable return.
Boardwalk Pipeline is subject to extensive regulations relating to the rates it can charge for its transportation and storage operations. For cost-based services, FERC establishes both the maximum and minimum rates Boardwalk Pipeline 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 through existing or future rates.
Customers or FERC can challenge the existing rates on any of its pipelines. Such a challenge against Boardwalk Pipeline could adversely affect its ability to establish reasonable transportation rates, to charge rates that would cover future increases in Boardwalk Pipeline’s 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 Boardwalk Pipeline were to file a rate case or defend its rates in a proceeding commenced by a customer or FERC, Boardwalk Pipeline would be required, among other things, to establish that the inclusion of an income tax allowance in Boardwalk Pipeline’s cost of service is just and reasonable. Under current FERC policy, since Boardwalk Pipeline is a limited partnership and does not pay U.S. federal income taxes, this would require Boardwalk Pipeline 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 Boardwalk Pipeline’s 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 Boardwalk Pipeline, which could result in a reduction of such maximum rates from current levels.
Continued development of new supply sources impacts demand for Boardwalk Pipeline’s services.
Supplies of natural gas in production areas that are closer to key end-user market areas than Boardwalk Pipeline’s supply sources may compete with gas originating in production areas connected to Boardwalk Pipeline’s system. For example, the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio, may cause gas in supply areas connected to Boardwalk Pipeline’s system to be diverted to market areas other than Boardwalk Pipeline’s traditional market areas and may adversely affect capacity utilization on Boardwalk Pipeline’s systems and its ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows. In addition, natural gas supplies from the Rocky Mountains and Canada may compete with and displace volumes from the Gulf Coast and Mid-Continent supply sources where Boardwalk Pipeline is located, which may also adversely affect Boardwalk Pipeline’s transportation volumes and the rates it can charge for its services.
Boardwalk Pipeline depends on certain key customers for a significant portion of its revenues.
Boardwalk Pipeline relies on a limited number of customers for a significant portion of revenues. Boardwalk Pipeline’s largest customer in terms of revenue, Devon Gas Services, LP, represented over 12% of Boardwalk Pipeline’s 2011 revenues and Boardwalk Pipeline expects this customer to account for more than 10% of its 2012 revenues. For 2011, Boardwalk Pipeline’s top ten customers comprised approximately 47% of its revenues. 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.
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 owed by customers for imbalances or gas loaned by Boardwalk Pipeline to them under certain no-notice and parking and lending services. FERC gas tariffs only allow Boardwalk Pipeline to require limited credit support in the event that transportation customers are unable to pay for its services. If any of Boardwalk Pipeline’s significant customers have credit or financial problems which result in a delay or failure to pay for services provided by Boardwalk Pipeline or contracted for with Boardwalk Pipeline, or to repay the gas they owe Boardwalk Pipeline, 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 Boardwalk Pipeline’s customers could also result in the non-renewal of contracted capacity.
Boardwalk Pipeline may incur higher than expected costs to maintain its pipeline systems.
Boardwalk Pipeline incurs substantial costs for ongoing maintenance of its pipeline systems and related facilities, some of which reflect increased regulatory requirements applicable to all interstate pipelines, including the pipeline integrity programs monitored by PHMSA. These costs may be capitalized or expensed, depending on the nature of the activity, and include those incurred for pipeline integrity management activities, equipment overhauls, general maintenance and repairs. Although Boardwalk Pipeline expects to complete the implementation of its current pipeline integrity program by the end of 2012, it could continue to incur substantial capital and operating expenditures beyond 2012 relating to the integrity and safety of its pipelines. In addition, there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require Boardwalk Pipeline to incur additional expenditures in the future.
Boardwalk Pipeline continues to pursue complex expansion projects which involve significant risks.
Boardwalk Pipeline may undertake large development projects in the future as it continues to pursue its growth strategy, including projects in new market areas or product lines. The successful completion of such projects, and the returns Boardwalk Pipeline may realize from those projects after completion, are subject to many significant risks, including cost overruns, delays in obtaining regulatory approvals, difficult construction conditions, including adverse weather conditions, delays in obtaining key materials, shortages of qualified labor, and escalating costs of labor and materials, particularly in the event there is a high level of construction activity in the pipeline industry at that time. As a result, Boardwalk Pipeline may not be able to complete future projects on the expected terms, cost or schedule, or at all. In addition, Boardwalk Pipeline cannot be certain that, if completed, it will be able to operate these projects, or that they will perform in accordance with expectations. Other areas of Boardwalk Pipeline’s business may suffer as a result of the diversion of management’s attention and other resources from other business concerns to its projects. Any of these factors could impair Boardwalk Pipeline’s ability to realize the benefits anticipated from the projects.
Boardwalk Pipeline’s future growth could be limited.
During the past several years, Boardwalk Pipeline completed a number of large development projects to enlarge and enhance its pipeline and storage systems. Boardwalk Pipeline plans to continue to grow and diversify its business by among other things investing in new assets through acquisition, developing a broader midstream service capability and accessing new markets such as the Marcellus Shale. Boardwalk Pipeline’s ability to grow, diversify and increase distributable cash flow per unit will depend, in part, on its ability to close and execute on accretive projects. Boardwalk Pipeline might not complete these large projects for any of the following reasons:
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inability to identify opportunities with favorable projected financial returns;
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inefficiencies and complexities that can occur because of unfamiliarity with new product lines or new markets;
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inability to raise financing for identified opportunities; or
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inability to secure sufficient commitments from potential customers due to competition from other companies or for other reasons.
Significant changes in energy prices could affect natural gas market supply and demand, or potentially reduce the competitiveness of natural gas compared with other forms of energy available to Boardwalk Pipeline’s customers, which could reduce system throughput and adversely affect Boardwalk Pipeline’s revenues and available cash.
Boardwalk Pipeline is currently experiencing extraordinarily low natural gas prices, which are being driven by the abundance of supply and increased infrastructure. Due to the natural decline in traditional gas production connected to Boardwalk Pipeline’s system, Boardwalk Pipeline’s success depends on its ability to obtain access to new sources of natural gas, which is dependent on factors beyond its control including the price level of natural gas. In general terms, the price of natural gas fluctuates in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:
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economic conditions;
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weather conditions, seasonal trends and hurricane disruptions;
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the relationship between the available supplies and the demand for natural gas;
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new supply sources;
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the availability of adequate transportation capacity;
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storage inventory levels;
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the price and availability of other forms of energy;
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the effect of energy conservation measures;
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the nature and extent of, and changes in, governmental regulation, for example greenhouse gas legislation and taxation; and
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the anticipated future prices of natural gas and other commodities.
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. Downward movement in gas prices could negatively impact producers in nontraditional supply areas such as the Barnett Shale, the Bossier Sands, the Cana Woodford Shale, the Fayetteville Shale and the Haynesville Shale, including producers who have contracted for capacity with Boardwalk Pipeline. Significant financial difficulties experienced by Boardwalk Pipeline’s producer customers could impact their ability to pay for services rendered or otherwise reduce their demand for Boardwalk Pipeline’s services.
High natural gas prices may result in a reduction in the 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 Boardwalk Pipeline’s services and could result in the non-renewal of contracted capacity as contracts expire.
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 rather than its investors. Each jurisdiction in which CNA does business has established supervisory agencies that regulate its business, including:
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standards of solvency, including risk-based capital measurements;
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restrictions on the nature, quality and concentration of investments;
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restrictions on CNA’s ability to withdraw from unprofitable lines of insurance or unprofitable market areas;
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the required use of certain methods of accounting and reporting;
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the establishment of reserves for unearned premiums, losses and other purposes;
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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;
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approval of policy forms;
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limitations on the ability of CNA’s insurance subsidiaries to pay dividends to us; and
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limitations on the ability to non-renew, cancel or change terms and conditions in policies.
Regulatory powers also extend to premium rate regulations which require that rates not be excessive, inadequate or unfairly discriminatory. CNA may also be required by the jurisdictions in which it does business to provide coverage to persons who would not otherwise be considered eligible. Each jurisdiction dictates the types of insurance and the level of coverage that must be provided to such involuntary risks. CNA’s share of these involuntary risks is mandatory and is generally a function of its respective share of the voluntary market by line of insurance in each jurisdiction.
Diamond Offshore. The 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 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 may significantly limit drilling activity.
In the aftermath of the Macondo well blowout in April of 2010 and the subsequent investigation into the causes of the event, new rules for oil and gas operations on the Outer Continental Shelf have been implemented, 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 employee training, engaging personnel in safety management and requiring third party audits of SEMS programs. 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 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 industries. 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.
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; 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.
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. 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. Several bills were introduced in the 111th and 112th Congress 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. Indications are that similar bills will continue to be introduced in the current Congress. 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.
Boardwalk Pipeline. Boardwalk Pipeline’s natural gas transportation and storage operations are subject to extensive regulation by FERC and the DOT among other federal and state authorities. In addition to FERC rules and regulations related to the rates Boardwalk Pipeline can charge for its services, federal regulations extend to pipeline safety, operating terms and conditions of service, the types of services Boardwalk Pipeline may offer, construction or abandonment of facilities, accounting and record keeping, and relationships and transactions with affiliated companies. These regulations can adversely impact Boardwalk Pipeline’s ability to compete for business, construct new facilities, including by increasing the lead times to develop projects, offer new services, or recover the full cost of operating its pipelines.
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 also 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.
We are subject to physical and financial risks associated with climate change.
As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our subsidiaries and their suppliers and customers. We and our subsidiaries may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and related services provided by our energy subsidiaries. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas. In addition, changing global weather patterns have been associated with extreme weather events and could change longer-term natural catastrophe trends, including increasing the frequency and severity of hurricanes and other natural disasters which could increase future catastrophe losses at CNA and damage to property, disruption of business and higher operating costs at Diamond Offshore, Boardwalk Pipeline, HighMount and Loews Hotels.
There is currently no federal regulation that limits GHG emissions in the U.S. However, several bills were introduced in Congress in recent years that would regulate U.S. GHG emissions under a cap and trade system. Although these bills were not passed into law, some regulation of that type may be enacted in the U.S. in the near future. In addition, in 2009 the EPA adopted regulations under the Clean Air Act requiring the monitoring and reporting of annual GHG emissions by operators of facilities that emit more than 25,000 metric tons of GHG per year, which includes Boardwalk Pipeline and HighMount. Numerous states and several regional multi-state climate initiatives have announced or adopted plans to regulate GHG emissions, though the state programs vary widely. The establishment of a GHG reporting system and registry may be a first step toward broader regulation of GHG emissions. Compliance with future laws and regulations could impose significant costs on affected companies or adversely affect the demand for and the cost to produce and transport hydrocarbon-based fuel, which would adversely affect the businesses of our energy subsidiaries.
We could incur impairment charges related to the carrying value of the long-lived assets and goodwill of our subsidiaries.
Our subsidiaries regularly evaluate their long-lived assets and goodwill for impairment whenever events or changes in circumstances indicate the carrying value of these assets may not be recoverable. Most notably, we could incur impairment charges related to the carrying value of offshore drilling equipment at Diamond Offshore, natural gas and oil properties at HighMount, pipeline equipment at Boardwalk Pipeline and hotel properties owned by Loews Hotels.
We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit’s fair value as of the testing date. We calculate the fair value of our reporting units (each of our principal operating subsidiaries) based on estimates of future discounted cash flows, which reflect management’s judgments and
assumptions regarding the appropriate risk-adjusted discount rate, future industry conditions and operations and other factors. Asset impairment evaluations are, by nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets which could impact the need to record an impairment charge and the amount of any charge taken.
We are a holding company and derive substantially all of our income and cash flow from our subsidiaries.
We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to holders of our common stock. Our subsidiaries are separate and independent legal entities and have no obligation, contingent or otherwise, to make funds available to us, whether in the form of loans, dividends or otherwise. The ability of our subsidiaries to pay dividends to us is also subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies, and their compliance with covenants in their respective loan agreements. Claims of creditors of our subsidiaries will generally have priority as to the assets of such subsidiaries over our claims and our creditors and shareholders.
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. We are currently a defendant in two such 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 148,000 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.
Information with respect to legal proceedings is incorporated by reference to Note 18 of the Notes to Consolidated Financial Statements included under Item 8.
Item 4. Mine Safety Disclosures.
None.
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:
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, 2011. 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, 2006 and that all dividends were reinvested.
(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 (included from December 14, 2006 when it began trading), Transocean Ltd. and The Travelers Companies, Inc.
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 2011 and 2010.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides certain information as of December 31, 2011 with respect to our equity compensation plans under which our equity securities are authorized for issuance.
(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 1,270 holders of record of our common stock.
Common Stock Repurchases
We repurchased our common stock in 2011 as follows:
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.
Management’s discussion and analysis of financial condition and results of operations is comprised of the following sections:
Page
No.
Overview
Consolidated Financial Results
Parent Company Structure
Critical Accounting Estimates
Results of Operations by Business Segment
CNA Financial
Reserves - Estimates and Uncertainties
CNA Specialty
CNA Commercial
Life & Group Non-Core
Other Insurance
Diamond Offshore
HighMount
Boardwalk Pipeline
Loews Hotels
Corporate and Other
Liquidity and Capital Resources
CNA Financial
Diamond Offshore
HighMount
Boardwalk Pipeline
Loews Hotels
Corporate and Other
Contractual Obligations
Investments
Accounting Standards Update
Forward-Looking Statements
OVERVIEW
We are a holding company. Our subsidiaries are engaged in the following lines of business:
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commercial property and casualty insurance (CNA Financial Corporation (“CNA”), a 90% owned subsidiary);
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operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc. (“Diamond Offshore”), a 50.4% owned subsidiary);
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exploration, production and marketing of natural gas and oil (including condensate and natural gas liquids), (HighMount Exploration & Production LLC (“HighMount”), a wholly owned subsidiary);
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interstate transportation and storage of natural gas (Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”), a 61% owned subsidiary); and
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operation of hotels (Loews Hotels Holding Corporation (“Loews Hotels”), a wholly owned subsidiary).
Unless the context otherwise requires, references in this Report to “Loews Corporation,” “the Company,” “Parent Company,” “we,” “our,” “us” or like terms refer to the business of Loews Corporation excluding its subsidiaries.
The following discussion should be read in conjunction with Item 1A, Risk Factors, and Item 8, Financial Statements and Supplementary Data of this Form 10-K.
Consolidated Financial Results
Consolidated net income for the year ended December 31, 2011 was $1.1 billion, or $2.63 per share, compared to net income of $1.3 billion, or $3.07 per share, in 2010. Net income for the fourth quarter of 2011 was $268 million, or $0.67 per share, compared to net income of $466 million, or $1.12 per share, in the 2010 fourth quarter.
Net income and earnings per share information attributable to Loews Corporation is summarized in the table below.
(a) Includes losses of $309 million (after tax and noncontrolling interests) in continuing operations and $19 million (after tax and noncontrolling interests) in discontinued operations for the year ended December 31, 2010 related to CNA’s Loss Portfolio Transfer transaction as discussed elsewhere in this MD&A.
Excluding the prior year charge of $328 million (after tax and noncontrolling interests) related to the Loss Portfolio Transfer transaction, net income decreased $552 million in 2011 as compared to 2010 primarily due to lower investment income from limited partnership results at CNA in 2011, higher catastrophe losses, a lower level of net prior year development recorded by CNA in 2011 than in 2010 and a $104 million (after tax and noncontrolling interests) increase in insurance reserves for CNA’s payout annuity business. The decrease in net income also reflected reduced results from the parent company trading portfolio due to lower performance of equity investments.
Net income also included net investment losses of $31 million (after tax and noncontrolling interests) in 2011 as compared to net investment gains of $27 million in the prior year. Net investment losses in 2011 were primarily driven by lower gains on sales of securities partially offset by lower other-than-temporary impairment losses at CNA.
Book value per common share increased to $47.49 at December 31, 2011 as compared to $44.51 at December 31, 2010.
Parent Company Structure
We are a holding company and derive substantially all of our cash flow from our subsidiaries. We rely upon our invested cash balances and distributions from our subsidiaries to generate the funds necessary to meet our obligations and to declare and pay any dividends to our shareholders. The ability of our subsidiaries to pay dividends is subject to, among other things, the availability of sufficient earnings and funds in such subsidiaries, applicable state laws, including in the case of the insurance subsidiaries of CNA, laws and rules governing the payment of dividends by regulated insurance companies (see Note 13 of the Notes to Consolidated Financial Statements included under Item 8) and compliance with covenants in their respective loan agreements. Claims of creditors of 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 and accident and health contracts represents the portion of premiums written related to the unexpired terms of coverage. The inherent risks associated with the reserving process are discussed in the Reserves - Estimates and Uncertainties section below.
Reinsurance and Other Receivables
An exposure exists with respect to the collectibility of property and casualty and life reinsurance ceded to the extent that any reinsurer is unable to meet its obligations or disputes the liabilities CNA has ceded under reinsurance agreements. An allowance for doubtful accounts on reinsurance receivables is recorded on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, CNA’s past experience and current economic conditions. Further information on CNA’s reinsurance receivables is included in Note 16 of the Notes to Consolidated Financial Statements included under Item 8.
Additionally, an exposure exists with respect to amounts due from customers on other receivables. An allowance for doubtful accounts is recorded on the basis of periodic evaluations of balances due currently or in the future, management’s experience and current economic conditions.
If actual experience differs from the estimates made by management in determining the allowances for doubtful accounts on reinsurance and other receivables, net receivables as reflected on our Consolidated Balance Sheets may not be collected. Therefore, our results of operations and/or equity could be materially adversely impacted.
Litigation
We and our subsidiaries are involved in various legal proceedings that have arisen during the ordinary course of business. We evaluate the facts and circumstances of each situation, and when management determines it necessary, a liability is estimated and recorded. Please read Note 18 of the Notes to Consolidated Financial Statements included under Item 8.
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 to sell 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 that are not observable in the market or cannot be derived principally from or corroborated by observable market data. These unobservable inputs represent our own judgment and are based on assumptions consistent with what we believe other market participants would use to price such securities. Given the susceptibility of financial markets to severe events as well as the level of uncertainty related to our assumptions and judgments, it is possible that changes in fair value estimates could have a material adverse impact on our results of operations and/or equity. Further information on fair value measurements is included in Note 4 of the Notes to Consolidated Financial Statements included under Item 8.
CNA’s investment portfolio is subject to market declines below amortized cost that may be other-than-temporary and therefore result in the recognition of impairment losses in earnings. Factors considered in the determination of whether or not a decline is other-than-temporary include a current intention or need to sell the security or an indication that a credit loss exists. Significant judgment exists regarding the evaluation of the financial condition and expected near-term and long term prospects of the issuer, the relevant industry conditions and trends, and whether CNA expects to receive cash flows sufficient to recover the entire amortized cost basis of the security. CNA has an Impairment Committee which reviews the investment portfolio on at least a quarterly basis, with ongoing analysis as new information becomes available. Further information on CNA’s process for evaluating impairments is included in Note 3 of the Notes to Consolidated Financial Statements included under Item 8.
Long Term Care Products and Payout Annuity Contracts
Future policy benefit reserves for CNA’s long term care products and payout annuity contracts and deferred acquisition costs for CNA’s long term care products are based on certain assumptions including morbidity, mortality, policy persistency and discount rates, which are impacted by expected investment yields. The recoverability of deferred acquisition costs and the adequacy of the reserves are contingent on actual experience related to these key assumptions, which were generally established at time of issue. If actual experience differs from these assumptions, the deferred acquisition costs may not be fully realized and the reserves may not be adequate, requiring CNA to add to reserves. Therefore, our results of operations and/or equity could be adversely impacted. The inherent risks associated with the reserving process are discussed in the Reserves - Estimates and Uncertainties section below.
Pension and Postretirement Benefit Obligations
We make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations to employees under our benefit plans. The assumptions that have the most impact on pension costs are the discount rate and the expected long term rate of return on plan assets. These assumptions are evaluated relative to current market factors such as inflation, interest rates and fiscal and monetary policies. Changes in these assumptions can have a material impact on pension obligations and pension expense.
In determining the discount rate assumption, we utilized current market information and liability information, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities. The yield curve was applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curves and indices evaluated in the selection of the discount rate are comprised of high quality corporate bonds that are rated AA by an accepted rating agency.
Further information on our pension and postretirement benefit obligations is included in Note 15 of the Notes to Consolidated Financial Statements included under Item 8.
Valuation of HighMount’s Proved Reserves
HighMount follows the full cost method of accounting for natural gas and oil exploration and production activities. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. The depletable base of costs includes estimated future costs to be incurred in developing proved natural gas and oil reserves, as well as 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. At March 31, 2009, total capitalized costs exceeded the ceiling and HighMount recognized non-cash impairment charges of $1.0 billion ($660 million after tax) related to the carrying value of natural gas and oil properties, as discussed further in Note 7 of the Notes to Consolidated Financial Statements included under Item 8. In addition, gains or losses on the sale or other disposition of natural gas and oil properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.
HighMount’s estimate of proved reserves requires a high degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. HighMount’s estimated proved reserves are based upon studies for each of its properties prepared by HighMount staff engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Determination of proved reserves is based on, among other things, (i) a pricing mechanism for oil and gas reserves which uses an average 12-month price; (ii) a limitation on the classification of reserves as proved undeveloped to locations scheduled to be drilled within five years; and (iii) a 10% discount factor used in calculating discounted future net cash flows.
The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of HighMount’s estimates or assumptions in the future and revisions to the value of HighMount’s proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. Given the volatility of natural gas and oil prices, it is possible that HighMount’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near term.
Impairment of Long-Lived Assets
The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company uses a probability-weighted cash flow analysis to test property and equipment for impairment based on relevant market data. If an asset is determined to be impaired, a loss is recognized to reduce the carrying amount to the fair value of the asset. Management’s cash flow assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from the reported amounts.
Goodwill
Goodwill is required to be evaluated on an annual basis and whenever, in management’s judgment, there is a significant change in circumstances that would be considered a triggering event. Management must apply judgment in assessing qualitatively whether events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Factors such as a reporting unit’s planned future operating results, long term growth outlook and industry and market conditions are considered. Judgment is also applied in determining the estimated fair value of reporting units’ assets and liabilities for purposes of performing quantitative goodwill impairment tests. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples.
At December 31, 2011, HighMount had $584 million of goodwill recorded in conjunction with its acquisition of certain exploration and production assets. HighMount performs its annual goodwill impairment test each April 30th and no impairment was determined at April 30, 2011. As a result of low natural gas prices and the potential ceiling test impairment discussed above, HighMount performed a goodwill impairment test as of December 31, 2011. No impairment charge was required based on that test.
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.
CNA Financial
Reserves - Estimates and Uncertainties
Property and Casualty Claim and Claim Adjustment Expense Reserves
CNA maintains loss reserves to cover its estimated ultimate unpaid liability for claim and claim adjustment expenses, including the estimated cost of the claims adjudication process, for claims that have been reported but not yet settled (case reserves) and claims that have been incurred but not reported (“IBNR”). Claim and claim adjustment expense reserves are reflected as liabilities and are included on the Consolidated Balance Sheets under the heading “Insurance Reserves.” Adjustments to prior year reserve estimates, if necessary, are reflected in results of operations in the period that the need for such adjustments is determined. The carried case and IBNR reserves as of each balance sheet date are provided in the Segment Results section of this MD&A and in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
The level of reserves CNA maintains represents its best estimate, as of a particular point in time, of what the ultimate settlement and administration of claims will cost based on CNA’s assessment of facts and circumstances known at that time. Reserves are not an exact calculation of liability but instead are complex estimates that CNA derives, generally
utilizing a variety of actuarial reserve estimation techniques, from numerous assumptions and expectations about future events, both internal and external, many of which are highly uncertain.
CNA is subject to the uncertain effects of emerging or potential claims and coverage issues that arise as industry practices and legal, judicial, social 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:
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the effects of worldwide economic conditions, which have resulted in an increase in the number and size of certain claims including both directors and officers (“D&O”) and errors and omissions (“E&O”) insurance claims related to corporate failures, as well as other coverages;
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class action litigation relating to claims handling and other practices; and
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mass tort claims, including bodily injury claims related to welding rods, benzene, lead, noise induced hearing loss, injuries from various medical products including pharmaceuticals and various other chemical and radiation exposure claims.
The impact of these and other unforeseen emerging or potential claims and coverage issues is difficult to predict and could materially adversely affect the adequacy of CNA’s claim and claim adjustment expense reserves and could lead to future reserve additions.
CNA’s property and casualty insurance subsidiaries also have actual and potential exposures related to asbestos and environmental pollution (“A&EP”) claims. CNA’s experience has been that establishing reserves for casualty coverages relating to A&EP claims and the related claim adjustment expenses are subject to uncertainties that are greater than those presented by other claims. Additionally, traditional actuarial methods and techniques employed to estimate the ultimate cost of claims for more traditional property and casualty exposures are less precise in estimating claim and claim adjustment reserves for A&EP. As a result, estimating the ultimate cost of both reported and unreported A&EP claims is subject to a higher degree of variability.
To mitigate the risks posed by CNA’s exposure to A&EP claims and claim adjustment expenses, as further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August 31, 2010, CNA completed a transaction with NICO, a subsidiary of Berkshire Hathaway Inc., under which substantially all of CNA’s legacy A&EP liabilities were ceded to NICO effective January 1, 2010.
Establishing Reserve Estimates
In developing claim and claim adjustment expense (“loss” or “losses”) reserve estimates, CNA’s actuaries perform detailed reserve analyses that are staggered throughout the year. The data is organized at a “product” level. A product can be a line of business covering a subset of insureds such as commercial automobile liability for small or middle market customers, it can encompass several lines of business provided to a specific set of customers such as dentists, or it can be a particular type of claim such as construction defect. Every product is analyzed at least once during the year, with the exception of certain run-off products which are analyzed on a periodic basis. The analyses generally review losses gross of ceded reinsurance and apply the ceded reinsurance terms to the gross estimates to establish estimates net of reinsurance. In addition to the detailed analyses, CNA reviews actual loss emergence for all products each quarter.
The detailed analyses use a variety of generally accepted actuarial methods and techniques to produce a number of estimates of ultimate loss. CNA’s actuaries determine a point estimate of ultimate loss by reviewing the various estimates and assigning weight to each estimate given the characteristics of the product being reviewed. The reserve estimate is the difference between the estimated ultimate loss and the losses paid to date. The difference between the estimated ultimate loss and the case incurred loss (paid loss plus case reserve) is IBNR. IBNR calculated as such includes a provision for development on known cases (supplemental development) as well as a provision for claims that have occurred but have not yet been reported (pure IBNR).
Most of CNA’s business can be characterized as long-tail. For long-tail business, it will generally be several years between the time the business is written and the time when all claims are settled. CNA’s long-tail exposures include
commercial automobile liability, workers’ compensation, general liability, medical, professional liability, other professional liability coverages, assumed reinsurance run-off and products liability. Short-tail exposures include property, commercial automobile physical damage, marine and warranty. CNA Specialty and CNA Commercial contain both long-tail and short-tail exposures. Other Insurance 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:
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paid development;
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incurred development;
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loss ratio;
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Bornhuetter-Ferguson using paid loss;
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Bornhuetter-Ferguson using incurred loss;
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frequency times severity; and
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stochastic modeling.
The paid development method estimates ultimate losses by reviewing paid loss patterns and applying them to accident years with further expected changes in paid loss. Selection of the paid loss pattern requires 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 requires 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 requires analysis of all of the factors 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 year. This method may be useful for immature accident 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 requires analysis of loss ratios from earlier accident 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 requires analysis of the same factors described above. This method assumes that only 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 requires consideration of all 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. 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 requires analysis of all the 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 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 requires 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 requires analysis of the impact of large losses and claim cost trends based on changes in the cost of repairing or replacing property, changes in the cost of medical care, changes in the cost of wage replacement, judicial decisions, legislative changes and other factors.
Stochastic modeling produces a range of possible outcomes based on varying assumptions related to the particular product being modeled. For some products, CNA uses models which rely on historical development patterns at an aggregate level, while other products are modeled using individual claim variability assumptions supplied by the claims department. In either case, multiple simulations are run and the results are analyzed to produce a range of potential outcomes. The results will typically include a mean and percentiles of the possible reserve distribution which aid in the selection of a point estimate.
For many exposures, especially those that can be considered long-tail, a particular accident 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 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 both CNA Commercial and CNA Specialty, the difference between CNA’s reserves and the actuarial point estimate is primarily driven by uncertainty with respect to immature accident years, claim cost inflation, changes in claims handling, tort reform roll-backs which may adversely impact claim costs, and the effects from the economy. For Other Insurance, 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 years. Some of these assumptions are explicit assumptions that are required of a particular method, but most of the assumptions are implicit and cannot be precisely quantified. An example of an explicit assumption is the pattern employed in the paid development method. However, the assumed pattern is itself based on several implicit assumptions such as the impact of inflation on medical costs and the rate at which claim professionals close claims. As a result, the effect on reserve estimates of a particular change in assumptions usually cannot be specifically quantified, and changes in these assumptions cannot be tracked over time.
CNA’s recorded reserves are management’s best estimate. In order to provide an indication of the variability associated with CNA’s net reserves, the following discussion provides a sensitivity analysis that shows the approximate estimated impact of variations in significant factors affecting CNA’s reserve estimates for particular types of business. These significant factors are the ones that CNA believes could most likely materially impact the reserves. This discussion covers the major types of business for which CNA believes a material deviation to its reserves is reasonably possible. There can be no assurance that actual experience will be consistent with the current assumptions or with the variation indicated by the discussion. In addition, there can be no assurance that other factors and assumptions will not have a material impact on CNA’s reserves.
Within CNA Specialty, CNA believes a material deviation to its net reserves is reasonably possible for professional liability and related business. This business includes professional liability coverages provided to various professional firms, including architects, real estate agents, small and mid-sized accounting firms, law firms and technology firms. This business also includes D&O, employment practices, fiduciary and fidelity coverages as well as insurance products serving the health care delivery system. The most significant factor affecting reserve estimates for this business is claim severity. Claim severity is driven by the cost of medical care, the cost of wage replacement, legal fees, judicial decisions, legislative changes and other factors. Underwriting and claim handling decisions such as the classes of business written and individual claim settlement decisions can also impact claim severity. If the estimated claim severity increases by 9%, CNA estimates that the net reserves would increase by approximately $450 million. If the estimated claim severity decreases by 3%, CNA estimates that net reserves would decrease by approximately $150 million. CNA’s net reserves for this business were approximately $4.9 billion at December 31, 2011.
Within CNA Commercial, the two types of business for which CNA believes a material deviation to its net reserves is reasonably possible are workers’ compensation and general liability.
For CNA Commercial workers’ compensation, since many years will pass from the time the business is written until all claim payments have been made, claim cost inflation on claim payments is the most significant factor affecting workers’ compensation reserve estimates. Workers’ compensation claim cost inflation is driven by the cost of medical care, the cost of wage replacement, expected claimant lifetimes, judicial decisions, legislative changes and other factors. If estimated workers’ compensation claim cost inflation increases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would increase by approximately $450 million. If estimated workers’ compensation claim cost inflation decreases by 100 basis points for the entire period over which claim payments will be made, CNA estimates that its net reserves would decrease by approximately $400 million. CNA’s net reserves for CNA Commercial workers’ compensation were approximately $5.0 billion at December 31, 2011.
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 $3.6 billion at December 31, 2011.
Given the factors described above, it is not possible to quantify precisely the ultimate exposure represented by claims and related litigation. As a result, CNA regularly reviews the adequacy of its reserves and reassesses its reserve estimates as historical loss experience develops, additional claims are reported and settled and additional information becomes available in subsequent periods.
In light of the many uncertainties associated with establishing the estimates and making the assumptions necessary to establish reserve levels, CNA reviews its reserve estimates on a regular basis and makes adjustments in the period that the need for such adjustments is determined. These reviews have resulted in CNA’s identification of information and trends that have caused CNA to change its reserves in prior periods and could lead to the identification of a need for additional material increases or decreases in claim and claim adjustment expense reserves, which could materially affect our results of operations and equity and CNA’s business and insurer financial strength and corporate debt ratings positively or negatively. See the Ratings section of this MD&A for further information regarding CNA’s financial strength and corporate debt ratings.
Life & Group Non-Core Policyholder Reserves
CNA calculates and maintains reserves for policyholder claims and benefits for its Life & Group Non-Core segment based on actuarial assumptions. The determination of these reserves is fundamental to its financial results and requires management to make assumptions about expected investment and policyholder experience over the life of the contract. Since many of these contracts may be in force for several decades, these assumptions are subject to significant estimation risk.
The actuarial assumptions represent management’s best estimate at the date the contract was issued plus a margin for adverse deviation. Actuarial assumptions include estimates of morbidity, mortality, policy persistency, discount rates and expenses over the life of the contracts. Under GAAP, these assumptions are locked in throughout the life of the contract unless a premium deficiency develops. The impact of differences between the actuarial assumptions and actual experience is reflected in results of operations each period.
Annually, management assesses the adequacy of its GAAP reserves by product group by performing premium deficiency testing. In this test, reserves computed using best estimate assumptions as of the date of the test without provisions for adverse deviation are compared to the recorded reserves. If reserves determined based on management’s current best estimate assumptions are greater than the existing net GAAP reserves (i.e. reserves net of any Deferred acquisition costs asset), the existing net GAAP reserves are adjusted to the greater amount.
Payout Annuity Reserves
CNA’s payout annuity reserves consist primarily of single premium group and structured settlement annuities. The annuity payments are generally fixed and are either for a specified period or contingent on the survival of the payee. These reserves are discounted except for reserves for loss adjustment expenses on structured settlements not funded by annuities in its property and casualty insurance companies. CNA has 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 current best estimate. The actuarial assumptions that management believes are subject to the most variability are discount rates and mortality.
The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.
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 rates, morbidity, and persistency, which can be impacted by policy lapses and death. The table below summarizes the estimated pretax impact on CNA’s results of operations from various hypothetical revisions to its assumptions. CNA has assumed that revisions to such assumptions would occur in each policy type, age and duration within each policy group. Although such hypothetical revisions are not currently required or anticipated, CNA believes they could occur based on past variances in experience and its expectations of the ranges of future experience that could reasonably occur.
It should be noted that CNA’s current GAAP long term care reserves contain a level of margin in excess of management’s current best estimates. Any required increase in the net GAAP reserves resulting from the hypothetical revisions in the table below would first reduce the margin before they would impact results of operations. The estimated impact to results of operations in the table below are after consideration of the existing margin.
Any actual adjustment would be dependent on the specific policies affected and, therefore, may differ from the estimates summarized above.
Results of Operations
The following table summarizes the results of operations for CNA for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8.
Loss Portfolio Transfer Reinsurance Agreement
As further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8, on August 31, 2010, CNA completed a transaction with NICO, a subsidiary of Berkshire Hathaway Inc., under which substantially all of its legacy A&EP liabilities were ceded to NICO (“Loss Portfolio Transfer”). We recognized a loss of $328 million (after tax and noncontrolling interests) in the third quarter of 2010, of which $309 million related to our continuing operations and $19 million related to our discontinued operations.
2011 Compared with 2010
Net income decreased $77 million in 2011 as compared with 2010. Excluding the loss associated with the Loss Portfolio Transfer, net income decreased $405 million in 2011 as compared with 2010. Net investment income decreased $262 million, reflecting significant unfavorable limited partnership results. In addition, investment gains (losses) decreased $105 million ($56 million after tax and noncontrolling interests). See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Partially offsetting these decreases was an $88 million increase in Insurance premiums. Insurance claims and policyholders’ benefits increased $504 million, primarily due to a lower level of favorable net prior year development, higher catastrophe losses and decreased results in CNA’s payout annuity business. CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, due to unlocking actuarial reserve assumptions for anticipated adverse changes in mortality and discount rates, which reflect the current low interest rate environment and CNA’s view of expected investment yields, as discussed in Life & Group Non-Core Policyholders Reserves above. Further information on net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
2010 Compared with 2009
Net income increased $239 million in 2010 as compared with 2009. This improvement was driven by significantly improved net investment results of $943 million ($551 million after tax and noncontrolling interests), partially offset by the loss associated with the Loss Portfolio Transfer. See the Investments section of this MD&A for further discussion of net realized investment results and net investment income. Favorable net prior year development of $594 million and $208 million was recorded for 2010 and 2009. Further information on net prior year development for the year ended December 31, 2010 and 2009 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8. Net earned premiums decreased $206 million in 2010 as compared with 2009, driven by a $176 million decrease in CNA Commercial and an $18 million decrease in CNA Specialty. See the CNA Segment Results section of this MD&A for further discussion. Net loss from discontinued operations increased $18 million in 2010 as compared to 2009, due to the loss associated with the Loss Portfolio Transfer.
In 2010, CNA commenced a program to significantly transform its Information Technology (“IT”) organization and delivery model. The total costs for this program were $37 million, of which $36 million was incurred through December 31, 2010.
Segment Results
CNA’s core property and casualty commercial insurance operations are reported in two business segments: CNA Specialty and CNA Commercial. CNA Specialty provides a broad array of professional, financial and specialty property and casualty products and services, primarily through insurance brokers and managing general underwriters. CNA Commercial includes property and casualty coverages sold to small businesses and middle market entities and organizations primarily through an independent agency distribution system. CNA Commercial also includes commercial insurance and risk management products sold to large corporations primarily through insurance brokers.
CNA’s non-core operations are managed in two segments: Life & Group Non-Core and Other Insurance. Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. Other Insurance primarily includes certain corporate expenses, including interest on corporate debt, and the results of certain property and casualty business primarily in run-off, including CNA Re and A&EP. Intersegment eliminations are also included in this segment.
CNA utilizes the net operating income financial measure to monitor its operations. Net operating income is calculated by excluding from net income the effects of (i) net realized investment gains or losses, (ii) income or loss from discontinued operations and (iii) any cumulative effects of changes in accounting guidance. In evaluating the results of the CNA Specialty and CNA Commercial segments, 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.
Changes in estimates of claim and allocated claim adjustment expense reserves and premium accruals, net of reinsurance, for prior years are defined as net prior year development within this MD&A. These changes can be favorable or unfavorable. Net prior year development does not include the impact of related acquisition expenses. Further information on CNA’s reserves is provided in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
The following discusses the results of continuing operations for CNA’s operating segments.
CNA Specialty
The following table summarizes the results of operations for CNA Specialty:
2011 Compared with 2010
Net written premiums for CNA Specialty increased $181 million in 2011 as compared with 2010, primarily driven by new business. Net earned premiums increased $117 million in 2011 as compared with 2010, consistent with increases in net written premiums in recent quarters and favorable premium development in 2011.
CNA Specialty’s average rate was flat for 2011, as compared to a decrease of 2.2% in 2010 for the policies that renewed in each period. Retention of 86.1% and 85.7% was achieved in each period.
Net income decreased $117 million in 2011 as compared with 2010. This decrease was due to lower net operating income and decreased net realized investment results.
Net operating income decreased $96 million in 2011 as compared with 2010, primarily due to lower favorable net prior year development and decreased net investment income.
The combined ratio increased 4.9 points in 2011 as compared with 2010. The loss ratio increased 5.3 points, primarily due to lower favorable net prior year development as well as the impact of a higher current accident year loss ratio. The 2011 current accident year loss ratio was unfavorably affected by the anticipated loss cost trend that exceeded earned rate levels.
Favorable net prior year development of $245 million and $344 million was recorded in 2011 and 2010. Further information on CNA Specialty’s net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
The following table summarizes the gross and net carried reserves for CNA Specialty:
2010 Compared with 2009
Net written premiums for CNA Specialty increased $7 million in 2010 as compared with 2009. Net written premiums increased in CNA’s professional management and liability lines of business. This increase was partially offset by continued decreased insured exposures and lower rates in CNA’s architects & engineers and CNA HealthPro lines of business due to economic and competitive market conditions. Net earned premiums decreased $18 million as compared with the same period in 2009, due to the impact of decreased net written premiums in prior quarters.
CNA Specialty’s average rate decreased 2.2% for 2010, as compared to a decrease of 1.6% in 2009 for policies that renewed in each period. Retention of 85.7% and 84.3% was achieved in each period.
Net income improved $159 million in 2010 as compared with 2009. This increase was due to improved net realized investment results and improved net operating income.
Net operating income improved $31 million in 2010 as compared with 2009, primarily due to increased favorable net prior year development and improved net investment income, partially offset by decreased current accident year underwriting results.
The combined ratio improved 1.5 points in 2010 as compared with 2009. The loss ratio improved 2.9 points, primarily due to increased favorable net prior year development, partially offset by the impact of a higher current accident year loss ratio. The expense ratio increased 1.2 points primarily related to higher underwriting expenses and higher commission rates. Underwriting expenses were unfavorably impacted by higher employee-related costs and IT costs.
Favorable net prior year development of $344 million was recorded in 2010, compared to $224 million in 2009. Further information on CNA Specialty’s net prior year development for 2010 and 2009 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
CNA Commercial
The following table summarizes the results of operations for CNA Commercial:
2011 Compared with 2010
Net written premiums for CNA Commercial increased $142 million in 2011 as compared with 2010. This increase was driven by continued positive rate achievement, improved economic conditions reflected in insured exposures, as well as lower reinsurance costs and higher new business levels in certain business lines.
CNA Commercial’s average rate increased 2.0% in 2011, as compared with an increase of 0.6% in 2010 for the policies that renewed in each period. Retention of 79.3% and 79.7% was achieved in each period.
Net income decreased $102 million in 2011 as compared with 2010. This decrease was due to lower net operating income, partially offset by improved net realized investment results.
Net operating income decreased $126 million in 2011 as compared with 2010. This decrease was primarily due to lower net investment income, higher catastrophe losses and lower favorable net prior year development. In addition, income tax expense of $22 million was recorded in the third quarter of 2011 due to an increase in the tax rate applicable to the undistributed earnings of a 50% owned subsidiary which was sold later in 2011. The sale did not result in a material after tax impact inclusive of this income tax expense. These unfavorable impacts were partially offset by improved non-catastrophe current accident year underwriting results, including lower expenses. In 2010, expenses were unfavorably impacted by IT costs.
The combined ratio increased 2.8 points in 2011 as compared with 2010. The loss ratio increased 4.1 points, primarily due to lower favorable net prior year development and higher catastrophe losses, partially offset by an improved current accident year non-catastrophe loss ratio. Catastrophe losses were $208 million, or 6.4 points of the loss ratio, for 2011, as compared to $113 million, or 3.5 points of the loss ratio, for 2010.
The expense ratio improved 1.2 points in 2011 as compared with 2010, primarily due to the favorable impact of recoveries in 2011 on insurance receivables written off in prior years and the impact of IT costs incurred in 2010.
Favorable net prior year development of $183 million and $256 million was recorded in 2011 and 2010. Further information on CNA Commercial net prior year development for 2011 and 2010 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
The following table summarizes the gross and net carried reserves for CNA Commercial:
2010 Compared with 2009
Net written premiums for CNA Commercial decreased $240 million in 2010 as compared with 2009. Premiums written were unfavorably impacted by decreased insured exposures and decreased new business as a result of competitive market conditions. Economic conditions led to decreased insured exposures, such as in the construction industry due to smaller payrolls and reduced project volume. Net earned premiums decreased $176 million in 2010 as compared with 2009, consistent with the trend of lower net written premiums.
CNA Commercial’s average rate increased 0.6% for 2010, as compared to flat rates for 2009 for the policies that renewed during those periods. Retention of 79.7% and 81.1% was achieved in each period.
Net income improved $212 million in 2010 as compared with 2009. This improvement was primarily due to improved net realized investment results.
Net operating income improved $14 million in 2010 as compared with 2009. This increase was primarily due to increased favorable net prior year development, partially offset by lower net investment income and higher catastrophe losses.
The combined ratio improved 3.1 points in 2010 as compared with 2009. The loss ratio improved 3.7 points, primarily due to increased favorable net prior year development, partially offset by the impact of higher catastrophe losses. Catastrophe losses were $113 million, or 3.5 points of the loss ratio, for 2010, as compared to $82 million, or 2.4 points of the loss ratio, for 2009.
The expense ratio increased 0.5 points in 2010 as compared with 2009, primarily due to the unfavorable impact of the lower net earned premium base. Underwriting expenses include the unfavorable impact of IT costs.
Favorable net prior year development of $256 million was recorded in 2010, compared to favorable net prior year development of $143 million in 2009. Further information on CNA Commercial net prior year development for 2010 and 2009 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
Life & Group Non-Core
The following table summarizes the results of operations for Life & Group Non-Core:
2011 Compared with 2010
Net earned premiums for Life & Group Non-Core decreased $13 million in 2011 as compared with 2010. Net earned premiums relate primarily to the individual and group long term care businesses.
Net loss increased $142 million in 2011 as compared with 2010 due to decreased results in CNA’s payout annuity, pension deposit and long term care businesses. In 2011, CNA’s payout annuity business was negatively impacted by a $104 million (after tax and noncontrolling interests) increase in insurance reserves, due to unlocking actuarial reserve assumptions for anticipated adverse changes in mortality and discount rates, which reflect the current low interest rate environment and CNA’s view of expected investment yields. 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. In 2011, a premium deficiency emerged and the actuarial reserve assumptions were unlocked and revised to management’s current best estimates. In 2010, CNA’s payout annuity reserves were increased by $35 million (after tax and noncontrolling interests), resulting from unlocking assumptions. Additionally, long term care claim reserves were increased by $30 million (after tax and noncontrolling interests) in 2011.
A number of CNA’s separate account pension deposit contracts guarantee principal and an annual minimum rate of interest. If aggregate contract value in the separate account exceeds the fair value of the related assets, an additional Policyholders’ funds liability is established. In 2011, CNA increased this pretax liability by $18 million. In 2010, CNA decreased this pretax liability by $24 million.
The increase in net loss was also impacted by decreased net realized investment results. In addition, 2010 includes favorable reserve development arising from a commutation of an assumed reinsurance agreement. These unfavorable impacts were partially offset by decreased expenses. In 2010, expenses were unfavorably impacted by IT costs.
The following table summarizes the net carried Life & Group Non-Core policyholder reserves:
(a) Reserve amounts are net of $1.4 billion and $1.5 billion of ceded reserves and exclude $627 million and $235 million of future policy benefits relating to Shadow Adjustments as of December 31, 2011 and 2010, as further discussed in Note 1 of the Notes to Consolidated Financial Statements included under Item 8. Reserves at December 31, 2011 also exclude $95 million of claim and claim adjustment expenses relating to Shadow Adjustments.
2010 Compared with 2009
Net earned premiums for Life & Group Non-Core decreased $13 million in 2010 as compared with 2009.
Net loss decreased $103 million in 2010 as compared with 2009. This improvement was primarily due to improved net realized investment results. In addition, 2009 results included the unfavorable impact of a $25 million (after tax and noncontrolling interests) legal accrual. The accrual was subsequently decreased in 2010 resulting in a favorable impact of $11 million (after tax and noncontrolling interests). Favorable reserve development arising from a commutation of an assumed reinsurance agreement in 2010 also contributed to the improvement.
These favorable impacts were partially offset by a $55 million (after tax and noncontrolling interests) gain recognized in 2009, net of reinsurance, arising from a settlement reached with Willis Limited that resolved litigation related to the placement of personal accident reinsurance.
The favorable impacts were also partially offset by the increase to payout annuity benefit reserves resulting from unlocking assumptions due to loss recognition, unfavorable results in CNA’s long term care business and less favorable performance on CNA’s pension deposit business.
During 2010 and 2009, CNA decreased the pretax liability in Policyholders’ funds related to its pension deposit business, as discussed above, by $24 million and $42 million, based on increases in the fair value of the investments supporting this business during those periods.
Other Insurance
The following table summarizes the results of operations for the Other Insurance segment, including A&EP and intersegment eliminations:
2011 Compared with 2010
Net loss decreased $265 million in 2011 as compared with 2010, primarily driven by the loss of $328 million (after tax and noncontrolling interests) as a result of the Loss Portfolio Transfer consummated in the third quarter of 2010. As a result of that transaction, the investment income allocated to the Other Insurance segment decreased substantially because of the lower net reserve base and associated risk capital. Claim adjustment expenses are lower because the counterparty to the Loss Portfolio Transfer is responsible for A&EP claim handling. The A&EP operations produced net operating income of $21 million (after tax and noncontrolling interests) for 2010.
Additionally, the decrease in net loss was driven by the favorable impact of a $22 million prior year tax amount and a $15 million pretax release of a previously established allowance for uncollectible reinsurance receivables arising from a change in estimate. These favorable impacts were partially offset by decreased net realized investment results and higher interest expense. The increase in interest expense primarily relates to the use of debt to fund a portion of the 2010 redemption of CNA’s preferred stock.
Favorable net prior year development of $3 million was recorded in 2011, compared to unfavorable net prior development of $6 million in 2010.
The following table summarizes the gross and net carried reserves for the Other Insurance segment:
2010 Compared with 2009
Net loss increased $218 million in 2010 as compared with 2009, driven by the loss of $328 million (after tax and noncontrolling interests) as a result of the Loss Portfolio Transfer. Net results were also impacted by lower net investment income and higher interest expense. Partially offsetting these unfavorable items were decreased unfavorable net prior year development and improved net realized investment results.
Unfavorable net prior year development of $6 million was recorded in 2010, and unfavorable net prior year development of $159 million was recorded in 2009 which included $79 million for asbestos exposures and $76 million for environmental pollution exposures. Further information on Other Insurance net prior year development for 2009 is included in Note 8 of the Notes to Consolidated Financial Statements included under Item 8.
Diamond Offshore
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. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political, regulatory and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within Diamond Offshore’s control and are difficult to predict.
Demand affects the number of days Diamond Offshore’s fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, Diamond Offshore may mobilize its rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, Diamond Offshore may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues.
As a result of anticipated downtime in the current year for rig mobilizations, regulatory surveys and shipyard projects, Diamond Offshore expects contract drilling revenue in 2012 to decline from the levels attained in 2011. Diamond Offshore also expects contract drilling revenue for some of its rigs to be lower as these rigs fulfill term commitments under contracts at lower dayrates than previously earned in 2011 and may not be able to benefit from higher dayrates that the market is currently bearing. For further information see Item 1A, Risk Factors - “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.”
Diamond Offshore’s operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. 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 2012 as a result of increased hiring and training activities as it continues the process of crewing three new drillships. Costs to repair and maintain equipment fluctuate depending upon the type of activity the drilling rig is performing, as well as the age and condition of the equipment and the regions in which Diamond Offshore’s rigs are working.
Diamond Offshore’s operating costs are also impacted by the regulatory environments in which it operates. The adoption of new regulations could result in additional inspection and certification costs, as well as require additional capital investment to comply with regulatory requirements. Accordingly, Diamond Offshore cannot fully predict the financial impact of any new regulations that may arise relating to drilling activities in the U.S. Gulf of Mexico (“GOM”), or elsewhere in the world. New laws or regulations may require an increase in capital spending for additional equipment to comply with such requirements. Diamond Offshore’s business could be negatively impacted by additional downtime which may be required to obtain necessary equipment and to install such equipment or to obtain the required inspections or certifications as prescribed under such regulations.
Operating expenses generally are not affected by changes in dayrates, and short term reductions in utilization do not necessarily result in lower operating expenses. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm stacked” state with a full crew. In addition, when a rig is idle, Diamond Offshore is responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, Diamond Offshore may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. Diamond Offshore recognizes, as incurred, operating expenses related to activities such as inspections, painting projects and routine
overhauls that meet certain criteria and which maintain rather than upgrade its rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods following capital upgrades.
Operating income is negatively impacted when Diamond Offshore performs certain regulatory inspections, which it refers to as a 5-year survey, or special survey, that are due every five years for each of Diamond Offshore’s rigs. Operating revenue decreases because these special surveys are 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. 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, operating income may 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 U.K. and Norwegian sectors of the North Sea.
During 2012, 11 of Diamond Offshore’s rigs will require 5-year surveys and one of its U.K. rigs will require dry-docking for inspections. Diamond Offshore expects these 12 rigs to be out of service for approximately 660 days in the aggregate. Diamond Offshore also expects to spend an additional approximately 440 days during 2012 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects. 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 our financial position, results of operations and cash flows. Under its insurance policy that expires on May 1, 2012, 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 insurance policy that expires on May 1, 2012, 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, which under the current policy commences on May 1 of each year.
Recent Developments
Diamond Offshore’s floating rigs accounted for approximately 94% of its contract drilling revenue during 2011. Industry wide floater utilization is greater than 90%, and, as of February 1, 2012, Diamond Offshore’s floating rigs were committed for approximately 75% of the days remaining in 2012 and 54% of 2013.
Internationally, the ultra-deepwater and deepwater floater markets are generally strong and also show signs of further strengthening, particularly in the ultra-deepwater segment where Diamond Offshore believes that there are few uncontracted rigs available to work in 2012. However, based on a December of 2011 analyst report, there are 49 ultra-deepwater and deepwater floaters under construction, which are expected to enter the market in 2012 and 2013. Many of these floaters, primarily those scheduled for delivery in 2013, are not yet contracted for future work.
Market strength for ultra-deepwater and deepwater rigs varies among geographic regions. Upcoming drilling programs offshore Brazil will require a number of additional ultra-deepwater rigs. This demand may be met by rigs constructed
domestically in Brazil, including 33 deepwater floaters ordered by Petrobras. However, additional demand for ultra-deepwater rigs could develop if Brazilian drilling programs, including those of Petrobras, are accelerated prior to delivery of domestically-constructed rigs. In addition, successful exploration and development programs in West Africa have given rise to a robust market for deepwater and ultra-deepwater rigs in that region.
Market strength for mid-water floaters is stable or improving depending on the geographic market. In the North Sea, the mid-water market is strong, with signs of increasing dayrates, and in the Mediterranean region, demand remains solid. The Southeast Asia and Australia markets also remain steady.
Four of Diamond Offshore’s marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Of Diamond Offshore’s two remaining marketed international jack-ups, one is currently working in Egypt, and the other, located in Montenegro, is actively seeking work.
Deepwater drilling activity in the GOM, while strengthening, continues to be impacted by the issuance of oil and gas drilling permits for operations on the Outer Continental Shelf (“OCS”) which has not yet returned to pre-Macondo levels. In addition, since the Macondo well blowout in 2010, more stringent and encompassing rules for oil and gas operations on the OCS have been implemented. Diamond Offshore has two actively marketed rigs in the GOM, consisting of one semisubmersible and one jack-up rig. The Ocean Victory and Ocean Columbia are currently operating in the GOM, both with contract backlog extending into the second quarter of 2012.
Contract Drilling Backlog
The following table reflects Diamond Offshore’s contract drilling backlog as of February 1, 2012, October 17, 2011 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011) and February 1, 2011 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2010). Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Diamond Offshore’s calculation also assumes full utilization of its drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92% - 98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in Diamond Offshore’s contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.
(a) Includes $1.9 billion attributable to contracted operations offshore Brazil for the years 2012 to 2015 and $1.8 billion attributable to future work for two of Diamond Offshore’s drillships under construction as of February 1, 2012.
(b) Includes $787 million attributable to contracted operations offshore Brazil for the years 2012 to 2016 as of February 1, 2012.
(c) Includes $1.6 billion attributable to contracted operations offshore Brazil for the years 2012 to 2015 as of February 1, 2012.
The following table reflects the amount of Diamond Offshore’s contract drilling backlog by year as of February 1, 2012:
(a) Includes $29 million and $299 million for the years 2013 and 2014, and $1.5 billion in the aggregate for the years 2015 to 2019, attributable to future work for two of Diamond Offshore’s drillships under construction as of February 1, 2012.
(b) Includes $507 million, $524 million, $524 million and $324 million for the years 2012 to 2015, attributable to contracted operations offshore Brazil.
(c) Includes $220 million, $222 million and $149 million for the years 2012 to 2014, and $196 million in the aggregate for the years 2015 to 2016, attributable to contracted operations offshore Brazil.
(d) Includes $631 million, $477 million, $368 million and $86 million for the years 2012 to 2015, attributable to contracted operations offshore Brazil.
The following table reflects the percentage of rig days committed by year as of February 1, 2012. 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.
(a) As of February 1, 2012, includes approximately 1,100 and 500 currently known, scheduled shipyard, survey and mobilization days for 2012 and 2013.
Dayrate and Utilization Statistics
(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) Utilization is calculated as the ratio of total revenue earnings days divided by the total calendar days in the period for all rigs in Diamond Offshore’s fleet (including cold stacked rigs).
(c) Average daily revenue is defined as contract drilling revenue (excluding revenue for mobilization, demobilization and contract preparation) per revenue earning day.
Results of Operations
The following table summarizes the results of operations for Diamond Offshore for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:
2011 Compared with 2010
Contract drilling revenue increased $24 million, or 0.7%, and net income increased $5 million, or 1.1%, in 2011 as compared with 2010. Revenue generated by Diamond Offshore’s floater rigs increased an aggregate $95 million, or 3.2% in 2011 as compared with 2010, while revenue generated by its jack-up fleet declined $71 million or 26.3%. Except for Diamond Offshore’s deepwater floaters, average daily revenue earned by its other rigs decreased during 2011 compared to the levels attained in 2010. Utilization for ultra-deepwater and deepwater floaters increased significantly in 2011 as compared with 2010; however, utilization for mid-water floater and jack-up fleets decreased in 2011. One additional mid-water floater and one jack-up rig were cold stacked during 2011. Diamond Offshore’s two newest floaters, the Ocean Courage and Ocean Valor, which began operating under contract late in the first quarter and in the fourth quarter of 2010, contributed incremental revenue of $162 million during 2011. Total contract drilling expense increased $158 million, or 11.4%, during 2011 as compared with 2010, reflecting incremental contract drilling expense for the Ocean Courage and Ocean Valor, higher amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.
Revenue from ultra-deepwater floaters increased $123 million in 2011 as compared with 2010, primarily due to increased utilization of $184 million, partially offset by a decrease in dayrates of $36 million. In addition, during the third quarter of 2010 Diamond Offshore received a $31 million contract termination fee related to the Ocean Endeavor. Revenue earning days increased by 514, primarily due to the Ocean Courage and Ocean Valor, which were under contract in Brazil for all of 2011 and worked a combined 353 incremental revenue earning days, compared to 2010, generating $162 million in incremental revenue. However, aggregate revenue earned by Diamond Offshore’s six other ultra-deepwater rigs decreased $39 million due to a lower average daily revenue earned, partially offset by an increase in revenue earning days due to downtime in 2010 associated with the relocation of three rigs from the GOM to international locations. Contract drilling expense for Diamond Offshore’s ultra-deepwater floaters increased $173 million primarily due to incremental contract drilling expense from the operation of the Ocean Courage and Ocean Valor, incremental mobilization expense and higher costs associated with operating rigs internationally.
Revenue from deepwater floaters increased $169 million in 2011 as compared with 2010. This increase was primarily due to a $152 million increase in utilization and $25 million increase in dayrates, partially offset by an $8 million decrease in amortized mobilization fees. Revenue earning days increased by 376 in 2011, primarily due to 209 fewer non-operating days for repairs, inspections and contract preparation activities, 87 fewer rig mobilization days and 80 fewer days in which rigs were warm stacked between contracts. Contract drilling expense for deepwater floaters increased $8 million primarily due to the Ocean America operating offshore Australia for all of 2011 compared to the prior year when the rig commenced drilling operations in June. This amount was partially offset by a reduction in recognized mobilization costs due to the full amortization of previously deferred costs as rigs completed their initial contracts.
Revenue from mid-water floaters decreased $197 million in 2011 as compared with 2010, primarily due to decreased utilization of $153 million, decreased dayrates of $59 million and decreased amortized mobilization fees of $9 million, partially offset by a $24 million demobilization fee received in relation to the Ocean Yorktown’s completion of its contract offshore Brazil. Revenue earning days decreased by 546, primarily attributable to 963 additional cold stacked days in 2011 compared to 2010, partially offset by 282 less warm stacked days between contracts, 84 less days for unpaid downtime for repairs and 51 less rig mobilization days. Contract drilling expense for mid-water floaters decreased $9 million and included a reduction in costs associated with cold stacked rigs, partially offset by an increase in personnel related costs, repairs and maintenance expense, shorebase support and overhead costs, including costs associated with the demobilization of the Ocean Yorktown to the GOM.
Revenue from jack-up rigs decreased $71 million in 2011 as compared with 2010, primarily due to decreased utilization of $71 million and decreased dayrates of $13 million, partially offset by a $13 million increase in amortized mobilization fees. Revenue earning days decreased by 810, reflecting the impact of cold stacking rigs during the period, the sale of the Ocean Shield in July 2010 and an increase in warm stacked days in between contracts, partially offset by a decrease in the number of non-revenue earning days for repairs and mobilization of rigs. Contract drilling expense for jack-ups decreased $21 million primarily due to reduced expense for cold stacked rigs and the Ocean Shield, partially offset by higher rig mobilization costs, inspection costs and hull insurance.
Net income increased in 2011 as compared with 2010, primarily due to the changes in contract drilling revenue and expense discussed above. In addition, interest expense decreased $18 million, primarily due to interest capitalized in 2011 on Diamond Offshore’s three drillships under construction. In 2010, Diamond Offshore recognized a pretax gain of $33 million related to the sale of the Ocean Shield.
Diamond Offshore’s annual effective tax rate decreased in 2011 as compared with 2010. The lower effective tax rate in the current year is primarily the result of differences in the mix of Diamond Offshore’s domestic and international pretax earnings and losses, as well as the mix of international tax jurisdictions in which Diamond Offshore operates. Also contributing to the lower effective tax rate in 2011 was the impact of a tax law provision that expired at the end of 2009 but was subsequently signed back into law in December 2010. This provision allows Diamond Offshore to defer recognition of certain foreign earnings for U.S. income tax purposes. The extension of this tax law provision, and Diamond Offshore’s decisions to build three new drillships overseas caused Diamond Offshore to reassess its intent to repatriate certain foreign earnings to the U.S. It is now Diamond Offshore’s intent to reinvest those earnings internationally. Consequently, Diamond Offshore is no longer providing taxes on those foreign earnings and has reversed previously accrued taxes related to those earnings.
2010 Compared with 2009
Contract drilling revenue decreased $307 million, or 8.7%, and net income decreased $197 million, or 30.6%, in 2010 as compared with 2009. Revenue generated by Diamond Offshore’s floater fleet decreased $118 million and revenue for its jack-up fleet decreased $189 million in 2010 as compared with 2009. In 2010, Diamond Offshore cold stacked three additional rigs in the GOM, consisting of two mid-water floaters and one jack-up rig. However, the two newest additions to Diamond Offshore’s floater fleet, the Ocean Courage and Ocean Valor, began operating under contract during the first and fourth quarters of 2010 and contributed $109 million to revenue. Additionally, Diamond Offshore recognized a gain in connection with the sale of the Ocean Shield in July of 2010, as discussed above. Total contract drilling expense increased $167 million and included normal operating costs for the Ocean Courage and Ocean Valor, as well as increased amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.
Revenue from ultra-deepwater floaters decreased $28 million in 2010 as compared with 2009, primarily due to decreased utilization of $58 million and decreased dayrates of $16 million, partially offset by a $31 million contract termination fee received in relation to the Ocean Endeavor, as well as a $15 million increase in amortized mobilization fees. During 2010, the Ocean Courage and Ocean Valor generated $109 million in revenue and worked a combined 280 revenue earning days. However, aggregate revenue earned by Diamond Offshore’s six other ultra-deepwater rigs decreased $137 million due to 437 fewer revenue earning days, largely resulting from effects of the April 20, 2010 Macondo well blowout in the GOM, as well as a decrease in average daily revenue earned. The decrease in revenue earning days was primarily attributable to increased downtime associated with incremental mobilization, contract preparation and customer acceptance days for three ultra-deepwater rigs that were relocated from the GOM to international locations in 2010 and unplanned downtime due to a force majeure assertion by a customer in the GOM following the Macondo incident. Contract drilling expense for ultra-deepwater floaters increased $111 million and included $85 million in incremental contract drilling expense incurred by the Ocean Courage and Ocean Valor, as well as $12 million in incremental mobilization expenses. Contract drilling expense in 2010 also reflected higher maintenance, inspection, freight, non-income based taxes and other revenue-based fees, partially offset by lower personnel and related costs, including a lower U.S. labor component as more of Diamond Offshore’s rigs worked internationally in 2010 compared to the prior year.
Revenue from deepwater floaters increased $38 million in 2010 as compared with 2009, primarily due to a $21 million increase in amortized mobilization fees and a $17 million increase in utilization. Revenue earning days increased by 44 in 2010 as compared with 2009 resulting from 165 fewer warm stacked days between contracts, partially offset by 80 additional non-revenue earning days due to scheduled shipyard time for inspections, repairs and contract preparation activities and 45 incremental rig mobilization days. Contract drilling expense for deepwater floaters increased $47 million primarily due to incremental mobilization expense, including amortized mobilization costs, increased personnel-related costs, higher revenue-based fees and shorebase support costs, which included costs related to Diamond Offshore’s Angola operations and higher costs related to its expanded operations offshore Brazil.
Revenue from mid-water floaters decreased $128 million in 2010 as compared with 2009, primarily due to a $114 million decrease in utilization and a $40 million decrease in dayrates, partially offset by a $26 million increase in amortized mobilization fees. Revenue earning days decreased by 397 primarily due to increased downtime during 2010 for repairs and the cold stacking of rigs, partially offset by fewer mobilization and warm stacked days. Contract drilling expense for mid-water floaters increased $59 million primarily due to higher personnel-related expenses, rig mobilization costs, including amortized mobilization expenses, revenue-based fees and taxes and shorebase support (Brazil and the Falkland Islands) and overhead costs.
Revenue from jack-up rigs decreased $189 million in 2010 as compared with 2009, primarily due to a $120 million decrease in dayrates, a $45 million decrease in utilization and a $24 million decrease in amortized mobilization fees. The decrease in average daily revenue earned during 2010 resulted primarily from all of Diamond Offshore’s jack-up rigs working at lower dayrates than those earned during 2009 due to weakened market conditions at the time. Utilization decreased from 66% in 2009 to 61% in 2010, reflecting 354 fewer revenue earning days, primarily due to the sale of the Ocean Shield and the impact of Diamond Offshore’s cold stacked rigs, including an additional jack-up rig cold stacked in September of 2010, partially offset by a decrease in downtime between contracts for actively marketed jack-ups. Amortized mobilization fees decreased primarily due to $15 million in deferred mobilization revenue recognized in 2009 by the Ocean Scepter upon completion of its contract offshore Argentina. Contract drilling expense for jack-ups decreased $46 million primarily due to reduced expense for Diamond Offshore’s cold stacked rigs and the Ocean Shield, which was sold in July 2010.
Net income decreased in 2010 as compared with 2009, primarily due to the changes in contract drilling revenue and expense discussed above. In addition, other operating expenses include an increase in depreciation of $47 million in 2010 due to a higher depreciable asset base, including depreciation on the Ocean Courage and Ocean Valor, which were placed in service in September 2009 and March 2010, but did not begin drilling operations until 2010. Interest expense increased $41 million due to a full year of interest expense in 2010 for Diamond Offshore’s issuance of 5.9% senior notes in May of 2009, and the issuance of 5.7% senior notes in October of 2009.
Diamond Offshore’s effective tax rate increased in 2010 as compared with 2009. The higher effective tax rate is a result of differences in the mix between its domestic and international pretax earnings or losses, as well as the mix of international tax jurisdictions in which Diamond Offshore operates. Also contributing to the higher effective tax rate in the current period were taxes associated with the sale of the Ocean Shield.
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. Since 2008 the price of natural gas and, to a lesser extent, NGLs has declined reflecting new sources of supply in shale formations and more efficient horizontal drilling techniques employed in shale formations. This has adversely impacted HighMount’s results of operations. The price of natural gas and oil as well as drilling costs, also impacts HighMount’s ability to realize attractive returns on the capital it employs to finance its drilling programs. In addition, the price HighMount realizes for its gas production is affected by its 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. 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, 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.
As discussed in Valuation of HighMount’s Proved Reserves in Critical Accounting Estimates, a ceiling test calculation is performed at the end of each quarterly period. HighMount’s December 31, 2011, ceiling test calculation was based on average 2011 prices of $4.12 per MMBtu for natural gas, $55.18 per Bbl for NGLs and $96.19 per Bbl for oil. Using these prices, total capitalized cost did not exceed the ceiling. The price of natural gas has declined from $4.41 per MMBtu on January 1, 2011 to $2.99 per MMBtu on January 1, 2012. If prices remain static throughout 2012, and holding all other assumptions constant, it is likely that HighMount would incur one or more material non-cash ceiling test impairments during the year. The potential impairment charge would be based on actual pricing at each measurement date.
Production and Sales Statistics
Presented below are production and sales statistics related to HighMount’s operations for 2011, 2010 and 2009:
In the second quarter of 2010, HighMount completed the sale of exploration and production assets located in the Antrim Shale in Michigan and the Black Warrior Basin in Alabama. The Michigan and Alabama properties represented approximately 17% in aggregate of HighMount’s total proved reserves as of December 31, 2009, prior to the sales.
Results of Operations
The following table summarizes the results of operations for HighMount for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included in Item 8.
2011 Compared with 2010
HighMount’s operating revenues decreased $65 million in 2011 as compared with 2010. Operating revenues decreased by $46 million due to the sale of HighMount’s assets in Michigan and Alabama in 2010. Permian Basin operating revenues decreased by $19 million on sales volumes of 60.6 Bcfe in 2011 compared to 66.5 Bcfe in 2010. Average prices realized per Mcfe for Permian Basin sales were $6.30 in 2011 compared to $6.02 in 2010, which reflects hedging activities. The decrease in Permian Basin sales volume is primarily due to the reduction in HighMount’s drilling activity in response to lower natural gas prices.
HighMount had hedges in place as of December 31, 2011 that covered approximately 51.7% and 16.3% of its total estimated 2012 and 2013 natural gas equivalent production at a weighted average price of $5.79 and $5.44 per Mcfe.
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. As a result of the Michigan and Alabama asset sales in 2010, HighMount recognized a pretax loss of $30 million in Investment losses related to its interest rate and commodity hedging activities. HighMount used the proceeds from the basin sales to reduce the outstanding debt under its term loans by $500 million, which resulted in a $15 million decrease in interest expense in 2011.
Operating expenses decreased $13 million in 2011 as compared with 2010. The decline reflects a $21 million decrease related to the sale of HighMount’s assets in Michigan and Alabama, partially offset by an $8 million increase in operating expenses in the Permian Basin. The increase in operating expenses is due to higher DD&A expenses, partially offset by lower general and administrative expenses.
DD&A expenses were $94 million and $92 million for the years ended December 31, 2011 and 2010. This reflects a $10 million increase in the Permian Basin, due to negative reserve revisions and projected future development, offset by an $8 million decrease due to the sale of HighMount’s assets in Michigan and Alabama.
2010 Compared with 2009
HighMount’s operating revenues decreased $165 million in 2010 as compared with 2009. Operating revenues decreased by $88 million due to the sale of HighMount’s assets in Michigan and Alabama. Permian Basin operating revenues decreased by $77 million on sales volumes of 66.5 Bcfe in 2010 compared to 74.6 Bcfe in 2009. Average
prices realized per Mcfe for Permian Basin sales were $6.02 in 2010 compared to $6.42 in 2009. The decrease in Permian Basin sales volume is primarily due to the reduction in HighMount’s drilling activity.
In the first quarter of 2009, HighMount recorded a non-cash ceiling test impairment charge of $1.0 billion ($660 million after tax) related to the carrying value of its natural gas and oil properties. The write-down was the result of declines in commodity prices. Had the effects of HighMount’s cash flow hedges not been considered in calculating the ceiling limitation, the impairment would have been $1.2 billion ($784 million after tax). No such impairment was required during 2010.
Operating expenses decreased $85 million in 2010 as compared with 2009. The decline reflects a $39 million decrease related to the sale of HighMount’s assets in Michigan and Alabama, partially offset by an $11 million adjustment to property impairment recorded in 2009. During 2009, HighMount incurred non-recurring operating expenses of $32 million related to fees for early termination rights on drilling rig contracts and a tubular inventory impairment charge. In addition, operating expenses in the Permian Basin decreased $25 million due to lower DD&A expenses, lower production and ad valorem taxes and cost cutting efforts in 2010.
DD&A expenses declined to $92 million in 2010, compared to $119 million in 2009, reflecting a $16 million decrease due to the sale of HighMount’s assets in Michigan and Alabama and an $11 million reduction in HighMount’s depletion rate in 2010, primarily due to the impairment of natural gas and oil properties recorded in 2009.
Boardwalk Pipeline
Boardwalk Pipeline derives revenues primarily from the interstate transportation and storage of natural gas for third parties. Transportation services consist of firm transportation, whereby 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 transportation, whereby the customer pays to transport gas only when capacity is available and used. Boardwalk Pipeline offers firm 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. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. Boardwalk Pipeline is not in the business of buying and selling natural gas other than for system management purposes, but changes in the level of natural gas prices may impact the volumes of gas transported on its pipeline systems. Boardwalk Pipeline’s operating costs and expenses typically do not vary significantly based upon the amount of gas transported, with the exception of fuel consumed at its compressor stations.
The majority of Boardwalk Pipeline’s revenues are derived from capacity reservation charges under firm agreements that are not impacted by the volume of natural gas transported or stored, and a smaller portion of revenues are derived from charges based on actual volumes transported under firm and interruptible services. For example, for the twelve months ended December 31, 2011, approximately 82% of Boardwalk Pipeline’s revenues were derived from capacity reservation charges and approximately 18% of Boardwalk Pipeline’s revenues were derived from charges based on actual volumes transported or stored.
As of December 31, 2011, a substantial portion of Boardwalk Pipeline’s transportation capacity has been contracted for under firm agreements having a weighted-average remaining life of approximately 6.0 years. However, an important aspect of Boardwalk Pipeline’s business is its ability to market available short term firm or interruptible transportation capacity and renew existing longer term transportation contracts. Boardwalk Pipeline actively markets its available capacity which includes reserved capacity not fully utilized. The revenues it will be able to earn from that available capacity and from renewals of expiring contracts will be influenced by basis spreads and other factors discussed below.
Boardwalk Pipeline’s ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on its pipeline systems (“basis spreads”), economic conditions and other factors. Over the past several years, new sources of natural gas have been identified throughout the U.S. and new pipeline infrastructure has been developed, which has led to changes in pricing dynamics between supply basins, pooling points and market areas and an overall weakening of basis spreads across its pipeline systems.
The narrowing of basis spreads on Boardwalk Pipeline’s pipeline systems has made it more difficult to renew expiring long term firm transportation contracts at previously contracted rates because, as basis spreads decrease, the rates customers are willing to pay decrease. In addition, as rates decline customers typically seek longer term agreements while Boardwalk Pipeline generally seeks shorter terms. Changing basis spreads do not have as significant or immediate of an impact on long term firm agreements as they do on short term or interruptible services because long term agreements are also influenced by other factors, such as baseload supply needs, certainty of delivery, predictability of long term costs, the ability to manage those costs through the capacity release mechanism and the terms of service. The changes in the pricing dynamics and weakening of basis spreads have contributed to decreases in Boardwalk Pipeline’s operating profitability especially with regard to short term and interruptible services. However, in 2011, revenues from power customers increased and Boardwalk Pipeline continues to see additional interest from this customer group.
Boardwalk Pipeline’s ability to market available storage capacity and PAL is impacted by many of the factors indicated above, as well as natural gas price differentials between time periods, such as winter to summer (“time period price spreads”). These time period price spreads have declined over the 2010 to 2011 periods and have resulted in a significant reduction in Boardwalk Pipeline’s PAL and interruptible storage revenues in 2011 as compared to 2010.
Results of Operations
The following table summarizes the results of operations for Boardwalk Pipeline for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:
2011 Compared with 2010
Total revenues increased $15 million in 2011 as compared with 2010. Gas transportation revenues, excluding fuel, increased $60 million primarily from increased capacities resulting from the completion of several compression projects in 2010 and operating the Fayetteville Lateral at its design capacity. PAL and storage revenues decreased $22 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods and fuel retained decreased $16 million primarily due to lower natural gas prices.
Operating expenses increased $65 million in 2011 as compared with 2010. The increase includes a $29 million impairment charge associated with Boardwalk Pipeline’s materials and supplies, most of which was subsequently sold. There were also higher operation and maintenance expenses of $18 million primarily due to maintenance projects for pipeline integrity management and reliability spending and lower amounts of labor capitalized from fewer growth projects and higher depreciation and property taxes of $12 million associated with an increase in the asset base. These increases were partially offset by lower fuel consumed of $9 million primarily due to lower natural gas prices. Interest expense increased by $22 million in 2011, primarily from a $13 million charge on the early extinguishment of debt and
$8 million resulting from higher average interest rates on Boardwalk Pipeline’s long term debt and lower capitalized interest.
Net income decreased $37 million in 2011 as compared with 2010 primarily due to the factors described above, as well as lower gains of $8 million on the sale of storage gas.
2010 Compared with 2009
Total revenues increased $219 million in 2010 as compared with 2009. Gas transportation revenues, excluding fuel, increased $199 million and fuel retained increased $31 million, primarily due to the pipeline expansion projects. In addition, there was an $18 million gain from the sale of gas related to the western Kentucky storage expansion project and a reduction in storage gas needed to support no-notice services. These increases were partially offset by $14 million of lower interruptible and short term firm transportation services resulting from lower basis spreads between delivery points on Boardwalk Pipeline’s pipeline systems. PAL and storage revenues decreased $9 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods.
Operating expenses increased $74 million in 2010 as compared with 2009. This increase was primarily driven by a $47 million increase in fuel consumed due to the pipeline expansion projects and higher natural gas prices. There was a $24 million increase in depreciation and property taxes due to a larger asset base from the pipeline expansion projects and a $10 million increase in operation and maintenance expenses due to an increase in major maintenance projects. The 2009 period was unfavorably impacted by $8 million of pipeline investigation and retirement costs related to the East Texas Pipeline. Interest expense increased $19 million due to higher debt levels in 2010 and lower capitalized interest due to the completion of Boardwalk Pipeline’s pipeline expansion projects.
Net income increased $47 million in 2010 as compared with 2009 due to higher revenues from transportation services primarily from the pipeline expansion projects and a gain on gas sales, partially offset by increased operating expenses related to higher depreciation and property taxes associated with the pipeline expansion projects and increased interest expense. In 2009, gas transportation revenues and throughput were negatively impacted due to operating the pipeline expansion projects at reduced operating pressures and portions of the pipeline expansion projects being shut down for periods of time following the discovery and remediation of anomalies in certain joints of pipe.
Loews Hotels
The following table summarizes the results of operations for Loews Hotels for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:
2011 Compared with 2010
Revenues increased by $29 million, or 9.4%, in 2011 as compared to 2010. Net income increased by $12 million as compared to 2010.
Revenue per available room increased $15.29 to $163.18 in 2011 as compared to 2010. The increase in revenue per available room reflects improving occupancy and average room rates. Occupancy rates increased to 73.6% in 2011 from 70.1% in 2010. Average room rates increased by $10.46, or 5.0%, in 2011 as compared to 2010.
The improvement in operating results for 2011 as compared to 2010 is due primarily to increases in revenue per available room described above, and increases in earnings from Orlando joint venture properties reflecting higher occupancy and average room rates.
Revenue per available room is an industry measure of the combined effect of occupancy rates and average room rates on room revenues. Other hotel operating revenues primarily include guest charges for food and beverages.
2010 Compared with 2009
Revenues increased by $24 million, or 8.5%, in 2010 as compared to 2009. Net income amounted to $1 million in 2010 as compared to a net loss of $34 million in 2009.
Revenue per available room increased $13.29 to $147.89 in 2010 as compared to 2009. The increase in revenue per available room reflects improving occupancy and average room rates. Occupancy rates increased to 70.1% in 2010 from 66.4% in 2009. Average room rates increased by $8.23, or 4.1%, in 2010 as compared to 2009.
Operating expenses in 2009 included aggregate pretax charges of $47 million due to the impact of the contracting U.S. economy. These charges included $27 million for the impairment of an investment in a Loews Hotels property, $10 million related to a development project commitment and $10 million for a loan guarantee at a managed hotel.
The improvement in operating results is primarily due to the absence of charges recorded in 2009 as discussed above, and also reflects the increase in revenue per available room in 2010.
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 managed to take advantage of potential market opportunities.
The following table summarizes the results of operations for Corporate and Other for the years ended December 31, 2011, 2010 and 2009 as presented in Note 21 of the Notes to Consolidated Financial Statements included under Item 8:
2011 Compared with 2010
Revenues decreased by $185 million in 2011 as compared to 2010. There was a net loss of $85 million in 2011 as compared to net income of $33 million in 2010. Due to less favorable equity investment returns and overall capital market volatility, the results of the trading portfolio were flat for 2011 as compared to significant gains in 2010. Earnings on cash and short term investments were also negatively impacted in 2011 by lower effective income yields.
2010 Compared with 2009
Revenues and net income in 2010 were relatively unchanged from 2009, and reflects improved earnings due to higher cash and short term investment balances and improved performance of the trading portfolio and limited partnership investments, partially offset by lower yields on cash and short term investments.
LIQUIDITY AND CAPITAL RESOURCES
CNA Financial
Cash Flows
CNA’s principal 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. Additionally, cash may be paid or received for income taxes.
For 2011, net cash provided by operating activities was $1.7 billion as compared with net cash used by operating activities of $89 million for 2010. As further discussed in Note 8 of the Notes to Consolidated Financial Statements included under Item 8 and previously referenced in this MD&A, in 2010 CNA completed the Loss Portfolio Transfer transaction. As a result of this transaction, operating cash flows were reduced for the initial net cash settlement with NICO. Excluding the impact of this transaction, net cash provided by operating activities was approximately $1.8 billion for 2010.
Cash flows resulting from reinsurance contract commutations are reported as operating activities. During 2011, operating cash flows were increased by $547 million related to net cash inflows from commutations as compared to net cash inflows of $189 million during 2010. Additionally, payments made for income taxes were $61 million for 2011 as compared to a refund of $175 million in 2010. Further, because cash receipts and cash payments resulting from purchases and sales of trading securities are reported as cash flows related to operating activities, during 2010 operating cash flows were increased by $153 million as compared to an increase of $1 million during 2011 related to trading activity. Excluding the items above, net cash generated by CNA’s business operations was approximately $1.2 billion for 2011 and $1.3 billion for 2010.
Net cash provided by operating activities was $1.3 billion in 2009. Operating cash flows were decreased by $164 million in 2009 related to net cash outflows which increased the size of the trading portfolio held at December 31, 2009.
Cash flows from investing activities include the purchase and sale 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 $1.1 billion for 2011, as compared with net cash provided of $767 million for 2010 and net cash used of $1.1 billion for 2009. 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. Net cash provided by investing activities in 2010 primarily related to the sale of short term investments which was used to fund the $1.9 billion initial net cash settlement with NICO as discussed above.
Cash flows from financing activities include proceeds from the issuance of debt and equity securities, outflows for stockholder dividends or repayment of debt and outlays to reacquire equity instruments.
Net cash used by financing activities was $644 million, $742 million and $120 million for 2011, 2010 and 2009. During 2011, CNA purchased the noncontrolling interest of CNA Surety and resumed payment of common stock dividends. Net cash used by financing activities in 2010 was primarily related to payments to redeem the outstanding 2008 Senior Preferred as discussed below.
2008 Senior Preferred and Surplus Note
In 2008, CNA issued, and Loews purchased, 12,500 shares of CNA non-voting cumulative senior preferred stock for $1.25 billion. CNA used the majority of the proceeds to increase the statutory surplus of its principal insurance subsidiary, Continental Casualty Company (“CCC”), through the purchase of a $1.0 billion surplus note of CCC. As of December 31, 2010, CNA has fully redeemed all 12,500 shares originally issued, through a series of redemptions during 2009 and 2010. The redemptions were funded by the issuance of debt and the partial repayment of the surplus note.
Dividends of $76 million and $122 million on the 2008 Senior Preferred were declared and paid for the years ended December 31, 2010 and 2009.
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 revolving credit facility, which provides for a total commitment of up to $250 million. This credit facility expires in August of 2012.
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 $0.40 per share of CNA’s common stock were declared and paid in 2011. On February 3, 2012, CNA’s Board of Directors declared a quarterly dividend of $0.15 per share, payable March 1, 2012 to stockholders of record on February 16, 2012. 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 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 and S&P for the property and casualty and life companies. The table also includes the ratings for CNA senior debt and The Continental Corporation (“Continental”) senior debt.
Insurance Financial Strength Ratings
Corporate Debt Ratings
Property & Casualty
Life
CNA
Continental
CCC
Group
Western
Group
CAC
Senior
Debt
Senior
Debt
A.M. Best
A
A
A-
bbb
Not rated
Moody’s
A3
Not rated
Not rated
Baa3
Baa3
S&P
A-
A-
Not rated
BBB-
BBB-
A.M. Best and Moody’s maintain a stable outlook on CNA. In 2011, S&P revised their outlook on CNA’s rating to positive from stable.
If CNA’s property and casualty insurance financial strength ratings were downgraded below current levels, its business and results of operations could be materially adversely affected. The severity of the impact on CNA’s business is dependent on the level of downgrade and, for certain products, which rating agency takes the rating action. Among the adverse effects in the event of such downgrades would be the inability to obtain a material volume of business from certain major insurance brokers, the inability to sell a material volume of CNA’s insurance products to certain markets and the required collateralization of certain future payment obligations or reserves. Downgrades of corporate debt ratings could result in adverse effects upon CNA’s liquidity position, including negatively impacting CNA’s ability to access capital markets, and increasing its financing costs.
Further, additional collateralization may be required for certain settlement agreements and assumed reinsurance contracts, as well as derivative contracts, if CNA’s ratings or other specific criteria fall below certain thresholds.
Diamond Offshore
Cash and investments totaled $1.2 billion at December 31, 2011, compared to $1.1 billion at December 31, 2010. In 2011, 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 1, 2012, 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 2011 was $1.4 billion, compared to $1.3 billion in 2010. Cash used in investing activities in 2011 increased $604 million compared to 2010. This increase was primarily due to capital expenditures related to the construction of Diamond Offshore’s three new drillships, as discussed below, as well as $186 million in proceeds received in relation to the sale of the Ocean Shield in 2010.
During 2011, Diamond Offshore paid $478 million as the first of two installments for the construction of its three new, ultra-deepwater drillships with delivery scheduled for the second and fourth quarters of 2013 and in the second quarter of 2014. The aggregate cost of the three drillships, including commissioning, spares and project management, is expected to be $1.8 billion. In addition, in 2011 Diamond Offshore spent approximately $285 million on capital expenditures associated with its ongoing rig equipment replacement and enhancement programs and other corporate requirements.
In December of 2011, Diamond Offshore entered into an agreement to construct a deepwater semisubmersible rig. The rig will be constructed utilizing the hull of one of Diamond Offshore’s mid-water floaters that previously operated as the Ocean Voyager. The project is estimated to be completed in the third quarter of 2013 at an aggregate cost of approximately $300 million, including commissioning, spares and project management costs.
For 2012, Diamond Offshore has budgeted approximately $220 million for capital expenditures associated with the construction of its new drillships and the Ocean Onyx and an additional $330 million for capital expenditures associated with its ongoing rig equipment replacement and enhancement programs and other corporate requirements. Diamond Offshore expects to finance its 2012 capital expenditures through the use of existing cash balances or internally generated funds.
Diamond Offshore’s liquidity and capital requirements are primarily a function of its working capital needs, capital expenditures and debt service requirements. Diamond Offshore determines the amount of cash required to meet its capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements, its ongoing rig equipment replacement and enhancement programs and its obligations relating to the construction of its three new drillships. As a result of Diamond Offshore’s intention to indefinitely reinvest the earnings of its wholly owned subsidiary, Diamond Offshore International Limited (“DOIL”), to finance its foreign activities, Diamond Offshore does not expect such earnings to be available for distribution to its stockholders or to finance its domestic activities. However, Diamond Offshore believes that the operating cash flows generated by and cash reserves of DOIL, and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc., will be sufficient to meet both its working capital requirements and its capital commitments over the next twelve months. Diamond Offshore will, however, continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.
HighMount
At December 31, 2011 and 2010, cash and investments amounted to $85 million and $130 million. Net cash flows provided by operating activities were $140 million and $197 million in 2011 and 2010. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.
Cash used in investing activities in 2011 was $292 million, compared to cash provided by investing activities of $351 million in 2010. In 2011, HighMount paid approximately $106 million for the acquisition of working interests in oil and gas properties as discussed in the Business section under Item 1. The acquisition was funded with a capital contribution from us. Cash provided by investing activities in 2010 includes the net proceeds from the sale of HighMount’s assets in Michigan and Alabama of approximately $530 million. The primary driver of cash used in investing activities was capital spent developing HighMount’s natural gas and oil reserves. HighMount spent $86 million and $104 million on capital expenditures for its drilling program in 2011 and 2010. HighMount expects to spend approximately $320 million on capital expenditures in 2012 developing its natural gas and oil reserves. Capital spending in 2012 will be focused on liquid-rich and oil drilling opportunities. Funds for capital expenditures and working capital requirements are expected to be provided primarily from operating activities and the available capacity under the revolving credit facility.
On December 1, 2011, HighMount refinanced its $1.1 billion term loans due on July 26, 2012 with proceeds from a new credit agreement and a $400 million capital contribution from us. The new credit agreement consists of a $600 million five year variable rate term loan and a five year $250 million revolving credit facility. At December 31, 2011, HighMount had $600 million of term loans and $100 million of revolving loans outstanding under its credit facility. As a result of the refinancing of its term loans in the fourth quarter of 2011, HighMount paid $38 million to terminate its interest rate swaps. For information regarding the refinancing see Note 11 of the Notes to Consolidated Financial Statements included in Item 8. In 2010 HighMount used proceeds from the sale of its assets in Michigan and Alabama to reduce the outstanding debt under its term loans by $500 million to $1.1 billion.
HighMount’s credit agreement governing its term loans and revolving credit facility contains financial covenants typical for these types of agreements, including a maximum debt to capitalization ratio and a minimum present value of proved natural gas and oil reserves to total debt ratio. The credit agreement also contains customary restrictions or limitations on HighMount’s ability to engage in certain transactions, including transactions with affiliates. At December 31, 2011, HighMount was in compliance with all of its covenants under the credit agreement.
Boardwalk Pipeline
At December 31, 2011 and 2010, cash and investments amounted to $23 million and $59 million. Funds from operations for the year ended December 31, 2011 amounted to $453 million, compared to $465 million in 2010. In 2011 and 2010, Boardwalk Pipeline’s capital expenditures were $142 million and $227 million.
In addition to the growth expenditures described below, in the next twelve months, Boardwalk Pipeline’s revolving credit facility and $225 million of 5.8% senior notes are due to mature. Boardwalk Pipeline’s ability to access the capital markets for debt and equity financing under reasonable terms depends on its financial condition, credit ratings and market conditions. Boardwalk Pipeline anticipates that its existing capital resources, including the revolving credit facility and future cash flows will be adequate to fund its operations, including its maintenance capital expenditures. Boardwalk Pipeline expects to issue and sell debt and/or equity securities for general corporate purposes, including to refinance outstanding debt or to fund potential acquisitions and new growth opportunities.
As of December 31, 2011, Boardwalk Pipeline had $458 million of loans outstanding under its revolving credit facility with a weighted-average interest rate on the borrowings of 0.5% and had no letters of credit issued. The revolving credit facility has a maturity date of June 29, 2012, however, all outstanding revolving loans on such date may be converted to term loans having a maturity date of June 29, 2013. As of December 31, 2011, Boardwalk Pipeline was in compliance with all covenant requirements under the credit facility. Subsequent to December 31, 2011, Boardwalk Pipeline repaid $115 million of borrowings, resulting in available borrowing capacity of $607 million.
In January and June of 2011, Boardwalk Pipeline issued $325 million and $115 million aggregate principal amount of 4.5% senior notes due February 1, 2021. The net proceeds of the offering were used to reduce borrowings under the revolving credit facility and redeem 5.5% Notes due April 1, 2013.
In June of 2011, Boardwalk Pipeline sold 6 million common units at a price of $29.33 per unit in a public offering and received net proceeds of $174 million, including a $4 million contribution by us to maintain our 2% general partner interest. The Company’s percentage ownership interest in Boardwalk Pipeline declined as a result of this transaction, from 66% to 64%. The issuance price of the common units exceeded the Company’s carrying amount, resulting in an increase to additional paid-in capital of $28 million.
In December of 2011, Boardwalk Pipeline contributed $70 million for a 20% equity interest in Boardwalk HP Storage Company, LLC (“HP Storage”).
In the first quarter of 2012, Boardwalk Pipeline sold 9.2 million common units at a price of $27.55 per unit in a public offering and received net proceeds of $250 million, including a $5 million contribution from us to maintain our 2% general partner interest. The net proceeds were used to repay borrowings under Boardwalk Pipeline’s revolving credit facility, which increased its available borrowing capacity under the facility.
Boardwalk Pipeline incurs substantial costs for ongoing maintenance of its pipeline systems and related facilities, some of which reflect increased regulatory requirements applicable to all interstate pipelines. These costs include those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. The Pipeline and Hazardous Materials Safety Administration has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. A recently enacted pipeline safety bill could result in increased regulatory requirements.
In 2012, Boardwalk Pipeline expects to incur costs of approximately $260 million related to its pipeline systems. Maintenance capital expenditures for 2012 are expected to be $91 million, of which $43 million is for system maintenance primarily related to pipeline integrity management. In 2011, these costs were approximately $250 million, of which $80 million was recorded as maintenance capital. The projected increase of $10 million is primarily related to pipeline integrity projects and general pipeline maintenance and repairs which are necessary to comply with regulatory requirements.
Boardwalk Pipeline’s more significant growth projects for 2012 consist of:
South Texas Eagle Ford Expansion: In 2012, Boardwalk Pipeline expects to spend approximately $180 million to construct a gathering pipeline and a cryogenic processing plant in south Texas.
Marcellus Gathering System: Boardwalk Pipeline expects to spend approximately $90 million to construct a gathering pipeline in Pennsylvania, of which it expects to spend approximately $70 million in 2012.
HP Storage: In 2012, HP Storage expects to spend approximately $35 million to leach a new salt dome storage cavern with a working gas capacity of approximately 5.0 Bcf. Boardwalk Pipeline currently owns a 20% equity interest in HP Storage. Boardwalk Pipeline could seek to acquire the remaining 80% equity interest in HP Storage that it does not currently own, if it makes economic sense for Boardwalk Pipeline and BPHC. Neither Boardwalk Pipeline nor BPHC is under any obligation with respect to such a transaction.
Loews Hotels
Funds from operations continue to exceed operating requirements. Cash and investments increased to $81 million at December 31, 2011 from $67 million at December 31, 2010. Funds for other capital expenditures, working capital requirements and mortgage debt coming due in the next twelve months are expected to be provided from existing cash balances, operations, refinancing, newly incurred debt and advances or capital contributions from the Parent Company.
Corporate and Other
Parent Company cash and investments, net of receivables and payables, at December 31, 2011 totaled $3.3 billion, as compared to $4.6 billion at December 31, 2010. During 2011, we paid $718 million to fund treasury stock purchases, repaid at maturity the entire $175 million principal amount of our 8.9% debentures and paid $101 million of cash dividends to our shareholders. These cash outflows were partially offset by the receipt of $624 million in interest and dividends from our subsidiaries.
During 2011, we also made capital contributions of $400 million to HighMount in connection with the refinancing of its term loans and $106 million to fund the acquisition of working interests in oil and gas properties. In addition, we paid $280 million for an 80% equity ownership interest in HP Storage, a joint venture with Boardwalk Pipeline.
As of December 31, 2011, there were 396,585,226 shares of Loews common stock outstanding. Depending on market and other conditions, we may purchase shares of our and our subsidiaries’ outstanding common stock in the open market or otherwise. During the year ended December 31, 2011, we purchased 18,205,438 shares of Loews common stock at an aggregate cost of $718 million.
We have an effective Registration Statement on Form S-3 registering the future sale of an unlimited amount of our debt and equity securities.
We continue to pursue conservative financial strategies while seeking opportunities for responsible growth. These include the expansion of existing businesses, full or partial acquisitions and dispositions, and opportunities for efficiencies and economies of scale.
Off-Balance Sheet Arrangements
At December 31, 2011 and 2010, we did not have any off-balance sheet arrangements.
Contractual Obligations
Our contractual payment obligations are as follows:
(a) Includes estimated future interest payments.
(b) Claim and claim adjustment expense reserves are not discounted and represent CNA’s estimate of the amount and timing of the ultimate settlement and administration of gross claims based on its assessment of facts and circumstances known as of December 31, 2011. See the Reserves - Estimates and Uncertainties section of this MD&A for further information.
(c) Future policy benefits and policyholders’ funds reserves are not discounted and represent CNA’s estimate of the ultimate amount and timing of the settlement of benefits based on its assessment of facts and circumstances known as of December 31, 2011. Future policy benefit reserves of $725 million and policyholders’ fund reserves of $36 million related to business which has been 100% ceded to unaffiliated parties in connection with the sale of CNA’s individual life business in 2004 are not included. Additional information on future policy benefits and policyholders’ funds reserves is included in Note 1 of the Notes to Consolidated Financial Statements included under Item 8.
(d) Diamond Offshore has entered three separate turnkey contracts for the construction of three ultra-deepwater drillships with
deliveries scheduled in 2013 and 2014. The aggregate cost of the three drillships is expected to be approximately $1.8 billion, of which $478 million was paid in 2011. The final installments of the contracted price are payable upon delivery of each vessel. Diamond Offshore has also entered into a construction contract to upgrade an existing rig. The upgrade is expected to be completed in 2013 at an aggregate cost of approximately $300 million.
(e) Does not include expected contribution of approximately $114 million to the Company’s pension and postretirement plans in 2012.
Further information on our commitments, contingencies and guarantees is provided in the Notes to Consolidated Financial Statements included under Item 8.
INVESTMENTS
Investment activities of non-insurance subsidiaries primarily include investments in fixed income securities, including short term investments. The Parent Company portfolio also includes equity securities, including short sales and derivative instruments, and investments in limited partnerships. These types of investments generally present greater volatility, less liquidity and greater risk than fixed income investments and are included within Results of Operations - Corporate and Other.
We enter into short sales and invest in certain derivative instruments that are used for asset and liability management activities, income enhancements to our portfolio management strategy and to benefit from anticipated future movements in the underlying markets. If such movements do not occur as anticipated, then significant losses may occur. Monitoring procedures include senior management review of daily detailed reports of existing positions and valuation fluctuations to ensure that open positions are consistent with our portfolio strategy.
Credit exposure associated with non-performance by the counterparties to derivative instruments is generally limited to the uncollateralized change in fair value of the derivative instruments recognized in the Consolidated Balance Sheets. We mitigate the risk of non-performance by monitoring the creditworthiness of counterparties and diversifying derivatives to multiple counterparties. We occasionally require collateral from our derivative investment counterparties depending on the amount of the exposure and the credit rating of the counterparty.
Insurance
CNA maintains a large portfolio of fixed maturity and equity securities, including large amounts of corporate and government issued debt securities, residential and commercial mortgage-backed securities, and other asset-backed securities and investments in limited partnerships which pursue a variety of long and short investment strategies across a broad array of asset classes. CNA’s investment portfolio supports its obligation to pay future insurance claims and provides investment returns which are an important part of CNA’s overall profitability.
Net Investment Income
The significant components of CNA’s pretax net investment income are presented in the following table:
Net investment income decreased $262 million in 2011 as compared with 2010. The decrease was primarily driven by a significant decrease in limited partnership results as well as lower fixed maturity security income. Limited partnership
results were adversely impacted by less favorable equity market returns, and overall capital market and credit spread volatility. The decrease in fixed maturity security income was primarily driven by reinvestment at lower market rates which led to a decline in the effective income yield of the portfolio.
Net investment income decreased $4 million in 2010 as compared with 2009. This decrease was primarily driven by less favorable income from CNA’s limited partnership investments, substantially offset by an investment shift during 2010 from lower yielding short term and tax-exempt securities to higher yielding taxable fixed maturity securities. The unfavorable year-over-year comparison in income from CNA’s limited partnership investments was driven by significant returns from CNA’s limited partnership investments in 2009.
The fixed maturity investment portfolio provided a pretax effective income yield of 5.5%, 5.6% and 5.7% for the years ended December 31, 2011, 2010, and 2009. Tax-exempt municipal bonds generated $240 million, $263 million and $381 million of net investment income for the years ended December 31, 2011, 2010 and 2009.
Net Realized Investment Gains (Losses)
The components of CNA’s net realized investment results are presented in the following table:
Net realized investment gains decreased $56 million for 2011 compared with 2010. Net realized investment results improved $551 million for 2010 as compared with 2009, driven by significantly lower other-than-temporary impairment (“OTTI”) losses recognized in earnings. Net realized investment results include OTTI losses of $140 million, $151 million, and $879 million for 2011, 2010 and 2009. Further information on CNA’s realized gains and losses, including CNA’s OTTI losses and impairment decision process, is set forth in Note 3 of the Notes to Consolidated Financial Statements included under Item 8. During the second quarter of 2009, the Company adopted updated accounting guidance, which amended the OTTI loss model for fixed maturity securities, as discussed in Note 1 of the Notes to Consolidated Financial Statements included under Item 8.
Portfolio Quality
CNA’s fixed maturity portfolio consists primarily of high quality bonds, 92.1% and 90.6% of which were rated as investment grade (rated BBB- or higher) at December 31, 2011 and 2010. The classification between investment grade and non-investment grade is based on a ratings methodology that takes into account ratings from two major providers,
S&P and Moody’s, in that order of preference. If a security is not rated by these providers, CNA formulates an internal rating. At December 31, 2011 and 2010, approximately 98% of the fixed maturity portfolio was issued or guaranteed by the U.S. Government, Government agencies or Government-sponsored enterprises or was rated by S&P or Moody’s.
The following table summarizes the ratings of CNA’s fixed maturity portfolio at fair value:
Non-investment grade fixed maturity securities, as presented in the table below, include high-yield securities rated below BBB- by bond rating agencies and other unrated securities that, according to CNA’s analysis, are below investment grade. Non-investment grade securities generally involve a greater degree of risk than investment grade securities. The amortized cost of CNA’s non-investment grade fixed maturity bond portfolio was $3.2 billion and $3.5 billion at December 31, 2011 and 2010. The following table summarizes the ratings of this portfolio at fair value.
The gross unrealized loss on available-for-sale fixed maturity securities was $536 million at December 31, 2011. The following table provides the maturity profile for these available-for-sale fixed maturity securities. Securities not due at a single date are allocated based on weighted average life.
Duration
A primary objective in the management of the investment portfolio is to optimize return relative to corresponding liabilities and respective liquidity needs. CNA’s views on the current interest rate environment, tax regulations, asset class valuations, specific security issuer and broader industry segment conditions, and the domestic and global economic conditions, are some of the factors that enter into an investment decision. CNA also continually monitors exposure to issuers of securities held and broader industry sector exposures and may from time to time adjust such exposures based on its views of a specific issuer or industry sector.
A further consideration in the management of the investment portfolio is the characteristics of the corresponding liabilities and the ability to align the duration of the portfolio to those liabilities and to meet future liquidity needs, minimize interest rate risk and maintain a level of income sufficient to support the underlying insurance liabilities. For portfolios where future liability cash flows are determinable and typically long term in nature, CNA segregates investments for asset/liability management purposes. The segregated investments support the liabilities in the Life & Group Non-Core segment including annuities, structured settlements and long term care products.
The effective durations of fixed maturity securities, short term investments, non-redeemable preferred stocks and interest rate derivatives are presented in the table below. Short term investments are net of payable and receivable amounts for securities purchased and sold, but not yet settled.
The investment portfolio is periodically analyzed for changes in duration and related price risk. Additionally, CNA periodically reviews the sensitivity of the portfolio to the level of foreign exchange rates and other factors that contribute to market price changes. A summary of these risks and specific analysis on changes is included in
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We are a large diversified holding company. As such, we and our subsidiaries have significant amounts of financial instruments that involve market risk. Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Changes in the trading portfolio are recognized in the Consolidated Statements of Income. Market risk exposure is presented for each class of financial instrument held by us at December 31, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results which may occur.
Exposure to market risk is managed and monitored by senior management. Senior management approves our overall investment strategy and has responsibility to ensure that the investment positions are consistent with that strategy with an acceptable level of risk. We may manage risk by buying or selling instruments or entering into offsetting positions.
Interest Rate Risk - We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. We attempt to mitigate our exposure to interest rate risk by utilizing instruments such as interest rate swaps, commitments to purchase securities, options, futures and forwards. We monitor our sensitivity to interest rate changes (inclusive of credit spread) by revaluing financial assets and liabilities using a variety of different interest rates. The Company uses duration and convexity at the security level to estimate the change in fair value that would result from a change in each security’s yield. Duration measures the price sensitivity of an asset to changes in the yield rate. Convexity measures how the duration of the asset changes with interest rates. The duration and convexity analysis takes into account the unique characteristics (e.g., call and put options and prepayment expectations) of each security, in determining the hypothetical change in fair value. The analysis is performed at the security level and is aggregated up to the asset category level.
The evaluation is performed by applying an instantaneous change in the yield rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on shareholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one year period.
The sensitivity analysis estimates the change in the fair value of our interest sensitive assets and liabilities that were held on December 31, 2011 and 2010 due to an instantaneous change in the yield of the security at the end of the period of 100 basis points, with all other variables held constant.
The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes of market interest rates on our earnings or shareholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.
Our debt is denominated in U.S. Dollars and has been primarily issued at fixed rates, therefore, interest expense would not be impacted by interest rate shifts. The impact of a 100 basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $455 million and $425 million at December 31, 2011 and 2010. The impact of a 100 basis point decrease would result in an increase in market value of $505 million and $464 million at December 31, 2011 and 2010. HighMount has entered into interest rate swaps for a notional amount of $300 million to hedge its exposure to fluctuations in LIBOR on a portion of its $700 million variable rate credit facility. These swaps effectively fix the interest rate at an effective rate of 3.4%. At December 31, 2011, the impact of a 100 basis point increase in interest rates on variable rate debt would increase interest expense by approximately $10 million on an annual basis.
Equity Price Risk - We have exposure to equity price risk as a result of our investment in equity securities and equity derivatives. Equity price risk results from changes in the level or volatility of equity prices which affect the value of equity securities or instruments that derive their value from such securities or indexes. Equity price risk was measured assuming an instantaneous 25% decrease in the underlying reference price or index from its level at December 31, 2011 and 2010, with all other variables held constant. A model was developed to analyze the observed changes in the value of limited partnerships held by the Company over a multiple year period along with the corresponding changes in various equity indices. The result of the model allowed us to estimate the change in value of limited partnerships when equity markets decline by 25%.
Foreign Exchange Rate Risk - Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. We have foreign exchange rate exposure when we buy or sell foreign currencies or financial instruments denominated in a foreign currency, which is reduced through the use of forward contracts. Our foreign transactions are primarily denominated in Australian dollars, Canadian dollars, British pounds, Brazilian reais and the European Monetary Unit. The sensitivity analysis assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2011 and 2010, with all other variables held constant.
Commodity Price Risk - We have exposure to price risk as a result of our investments in commodities. Commodity price risk results from changes in the level or volatility of commodity prices that impact instruments which derive their value from such commodities. Commodity price risk was measured assuming an instantaneous increase of 20% from their levels at December 31, 2011 and 2010. The impact of a change in commodity prices on the Company’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the underlying hedged transaction, such as revenue from sales.
Credit Risk - We are exposed to credit risk relating to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Although nearly all of the Company’s customers pay for its services on a timely basis, the Company actively monitors the credit exposure to its customers. Certain of the Company’s subsidiaries may perform credit reviews of customers and may require customers to provide cash collateral, post a letter of credit, prepay for services or provide other credit enhancements.
Boardwalk Pipeline has established credit policies in the pipeline tariffs which are intended to minimize credit risk in accordance with FERC policies and actively monitors this portion of its business. Boardwalk Pipeline’s credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by Boardwalk Pipeline to them, generally under PAL and no-notice services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. If any significant customer of Boardwalk Pipeline should have credit or financial problems resulting in a delay or failure to repay the gas they owe to Boardwalk Pipeline, this could have a material adverse effect on Boardwalk Pipeline’s business, financial condition, results of operations and cash flows. As of December 31, 2011, the amount of gas loaned out by Boardwalk Pipeline or owed to Boardwalk Pipeline due to gas imbalances was approximately 8.3 trillion British thermal units (TBtu). Assuming an average market price during December 2011 of $3.14 per million British thermal unit (MMBtu), the market value of this gas at December 31, 2011, would have been approximately $26 million. As of December 31, 2010, the amount of gas loaned out by Boardwalk Pipeline or owed to Boardwalk Pipeline due to gas imbalances was approximately 13.0 TBtu. Assuming an average market price during December 2010 of $4.21 per MMBtu, the market value of this gas at December 31, 2010, would have been approximately $55 million.
The following tables present our market risk by category (equity prices, interest rates, foreign exchange rates and commodity prices) on the basis of those entered into for trading purposes and other than trading purposes.
Trading portfolio:
Note:
The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of (1) a decrease in equity prices of 25% and (2) an increase in yield rates of 100 basis points. Adverse changes on options which differ from those presented above would not necessarily result in a proportionate change to the estimated market risk exposure.
Other than trading portfolio:
Note:
The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of (1) a decrease in equity prices of 25%, (2) an increase in yield rates of 100 basis points, (3) a decrease in the foreign currency exchange rates versus the U.S. dollar of 20% and (4) an increase in commodity prices of 20%.
(a) Certain securities are denominated in foreign currencies. An assumed 20% decline in the underlying exchange rates would result in an aggregate foreign currency exchange rate risk of $(382) and $(362) at December 31, 2011 and 2010.
(b) The market risk at December 31, 2011 and 2010 will generally be offset by recognition of the underlying hedged transaction.
Item 8. Financial Statements and Supplementary Data.
Financial Statements and Supplementary Data are comprised of the following sections:
Page
No.
Management’s Report on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Statements of Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements:
1.
Summary of Significant Accounting Policies
2.
Acquisition/Divestitures
3.
Investments
4.
Fair Value
5.
Derivative Financial Instruments
6.
Receivables
7.
Property, Plant and Equipment
8.
Claim and Claim Adjustment Expense Reserves
9.
Leases
10.
Income Taxes
11.
Debt
12.
Shareholders’ Equity
13.
Statutory Accounting Practices (Unaudited)
14.
Supplemental Natural Gas and Oil Information (Unaudited)
15.
Benefit Plans
16.
Reinsurance
17.
Quarterly Financial Data (Unaudited)
18.
Legal Proceedings
19.
Commitments and Contingencies
20.
Business Segments
21.
Consolidating Financial Information
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for us. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2011, our internal control over financial reporting was effective.
Our independent registered public accounting firm, Deloitte & Touche LLP, has issued an audit report on the Company’s internal control over financial reporting. The report of Deloitte & Touche LLP follows this Report.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Loews Corporation
New York, NY
We have audited the internal control over financial reporting of Loews Corporation and subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2011 and our report dated February 22, 2012 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the change in method of accounting for other-than-temporary impairments.
/s/ DELOITTE & TOUCHE LLP
New York, NY
February 22, 2012
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Loews Corporation
New York, NY
We have audited the accompanying consolidated balance sheets of Loews Corporation and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Loews Corporation and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 of the Notes to Consolidated Financial Statements, the Company changed its method of accounting for other-than-temporary impairments.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New York, NY
February 22, 2012
Loews Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF EQUITY
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF EQUITY
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Loews Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
Loews Corporation and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Basis of presentation - Loews Corporation is a holding company. Its subsidiaries are engaged in the following lines of business: commercial property and casualty insurance (CNA Financial Corporation (“CNA”), a 90% owned subsidiary); the operation of offshore oil and gas drilling rigs (Diamond Offshore Drilling, Inc. (“Diamond Offshore”), a 50.4% owned subsidiary); exploration, production and marketing of natural gas and oil (including condensate and NGLs), (HighMount Exploration & Production LLC (“HighMount”), a wholly owned subsidiary); interstate transportation and storage of natural gas (Boardwalk Pipeline Partners, LP (“Boardwalk Pipeline”), a 61% owned subsidiary); and the operation of hotels (Loews Hotels Holding Corporation (“Loews Hotels”), a wholly owned subsidiary). Unless the context otherwise requires, the terms “Company,” “Loews” and “Registrant” as used herein mean Loews Corporation excluding its subsidiaries and the term “Net income (loss) - Loews” as used herein means Net income (loss) attributable to Loews Corporation.
Principles of consolidation - The Consolidated Financial Statements include all subsidiaries and intercompany accounts and transactions have been eliminated. The equity method of accounting is used for investments in associated companies in which the Company generally has an interest of 20% to 50%.
Accounting estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and the related notes. Actual results could differ from those estimates.
Accounting changes - In April of 2009, the Financial Accounting Standards Board (“FASB”) issued updated accounting guidance which amended the other-than-temporary impairment (“OTTI”) loss model for fixed maturity securities. The implementation of this updated accounting guidance as of April 1, 2009 resulted in a cumulative effect adjustment of $109 million (after tax and noncontrolling interest), which was reclassified to Accumulated other comprehensive income (loss) (“AOCI”) from Retained earnings on the Consolidated Statements of Equity. The cumulative effect adjustment represents the non-credit component of those previously impaired fixed maturity securities that were still considered OTTI, and the entire amount previously recorded as an OTTI loss on fixed maturity securities no longer considered OTTI as of April 1, 2009. Further information on OTTI loss is included in Note 3 of the Notes to Consolidated Financial statements.
Investments - The Company classifies its fixed maturity securities and equity securities as either available-for-sale or trading, and as such, they are carried at fair value. Short term investments are carried at fair value. Changes in fair value of trading securities are reported within Net investment income on the Consolidated Statements of Income. Changes in fair value related to available-for-sale securities are reported as a component of Other comprehensive income. The cost of fixed maturity securities classified as available-for-sale is adjusted for amortization of premiums and accretion of discounts to maturity, which are included in Net investment income on the Consolidated Statements of Income. Losses may be recognized within the Consolidated Statements of Income when a decline in value is determined by the Company to be other-than-temporary.
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 is recorded, net of tax and noncontrolling interests, as a reduction of net unrealized gains through Other comprehensive income (“Shadow Adjustments”). For the years ended December 31, 2011 and 2010, Shadow Adjustments, net of participating policyholders’ interest, of $524 million and $135 million, were recorded, (after tax and noncontrolling interests). At December 31, 2011 and 2010, net unrealized gains on investments included in AOCI were correspondingly reduced by $659 million and $135 million (after tax and noncontrolling interests).
For asset-backed securities included in fixed maturity securities, the Company recognizes income using an effective yield based on anticipated prepayments and the estimated economic life of the securities. When estimates of prepayments change, the effective yield is recalculated to reflect actual payments to date and anticipated future
payments. The amortized cost of high credit quality securities is adjusted to the amount that would have existed had the new effective yield been applied since the acquisition of the securities. Such adjustments are reflected in Net investment income on the Consolidated Statements of Income. Interest income on lower rated securities is determined using the prospective yield method.
The Company’s carrying value of investments in limited partnerships is its share of the net asset value of each partnership, as determined by the General Partner. Certain partnerships for which results are not available on a timely basis are reported on a lag, primarily three months or less. These investments are accounted for under the equity method and changes in net asset values are recorded within Net investment income on the Consolidated Statements of Income.
Investments in derivative securities are carried at fair value with changes in fair value reported as a component of Investment gains (losses), Income (loss) from trading portfolio, or Other comprehensive income (loss), depending on their hedge designation. A derivative is typically defined as an instrument whose value is “derived” from an underlying instrument, index or rate, has a notional amount, requires little or no initial investment and can be net settled. Derivatives include, but are not limited to, the following types of investments: interest rate swaps, interest rate caps and floors, put and call options, warrants, futures, forwards, commitments to purchase securities, credit default swaps and combinations of the foregoing. Derivatives embedded within non-derivative instruments (such as call options embedded in convertible bonds) must be split from the host instrument when the embedded derivative is not clearly and closely related to the host instrument.
Hedging - The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedging transactions. The Company also formally assesses (both at the hedge’s inception and on an ongoing basis) whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in fair value or cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. When it is determined that a derivative for which hedge accounting has been designated is not (or ceases to be) highly effective, the Company discontinues hedge accounting prospectively. See Note 5 for additional information on the Company’s use of derivatives.
Securities lending activities - The Company lends securities for the purpose of enhancing income or to finance positions to unrelated parties who have been designated as primary dealers by the Federal Reserve Bank of New York. Borrowers of these securities must deposit and maintain collateral with the Company of no less than 100% of the fair value of the securities loaned. U.S. Government securities and cash are accepted as collateral. The Company maintains effective control over loaned securities and, therefore, continues to report such securities as investments on the Consolidated Balance Sheets.
Securities lending is typically done on a matched-book basis where the collateral is invested to substantially match the term of the loan. This matching of terms tends to limit risk. In accordance with the Company’s lending agreements, securities on loan are returned immediately to the Company upon notice. Collateral is not reflected as an asset of the Company. There was no collateral held at December 31, 2011 and 2010.
Revenue recognition - Premiums on property and casualty insurance contracts are recognized in proportion to the underlying risk insured which principally are earned ratably over the duration of the policies. Premiums on accident and health insurance contracts are earned ratably over the policy year in which they are due. The reserve for unearned premiums on these contracts represents the portion of premiums written relating to the unexpired terms of coverage.
Insurance receivables include balances due currently or in the future, including amounts due from insureds related to losses under high deductible policies, and are presented at unpaid balances, net of an allowance for doubtful accounts. Amounts are considered past due based on policy payment terms. That allowance is determined based on periodic evaluations of aged receivables, management’s experience and current economic conditions. Insurance receivables and any related allowance are written off after collection efforts are exhausted or a negotiated settlement is reached.
Property and casualty contracts that are retrospectively rated contain provisions that result in an adjustment to the initial policy premium depending on the contract provisions and loss experience of the insured during the experience period. For such contracts, CNA estimates the amount of ultimate premiums that it may earn upon completion of the experience period and recognizes either an asset or a liability for the difference between the initial policy premium and the estimated ultimate premium. CNA adjusts such estimated ultimate premium amounts during the course of the experience period based on actual results to date. The resulting adjustment is recorded as either a reduction of or an increase to the earned premiums for the period.
Contract drilling revenue from dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, Diamond Offshore may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. Absent a contract, mobilization costs are recognized currently. From time to time, Diamond Offshore may receive fees from its customers for capital improvements to their rigs. Diamond Offshore defers such fees received and recognizes these fees into revenue on a straight-line basis over the period of the related drilling contract. Diamond Offshore capitalizes the costs of such capital improvements and depreciates them over the estimated useful life of the improvement.
HighMount’s natural gas and oil production revenue is recognized based on actual volumes of natural gas and oil sold to purchasers. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed. Natural gas and oil production revenue is reported net of royalties. HighMount uses the sales method of accounting for gas imbalances. An imbalance is created when the volumes of gas sold by HighMount pertaining to a property do not equate to the volumes produced to which HighMount is entitled based on its interest in the property. An asset or liability is recognized to the extent that HighMount has an imbalance in excess of the remaining reserves on the underlying properties.
Revenues from the transportation of natural gas are recognized in the period the service is provided based on contractual terms and the related transported volumes. Revenues from storage services are recognized over the term of the contract. Boardwalk Pipeline’s operating subsidiaries are subject to Federal Energy Regulatory Commission (“FERC”) regulations and, accordingly, certain revenues collected may be subject to possible refunds to its customers. An estimated refund liability is recorded considering regulatory proceedings, advice of counsel and estimated total exposure.
Claim and claim adjustment expense reserves - Claim and claim adjustment expense reserves, except reserves for structured settlements not associated with asbestos and environmental pollution (“A&EP”), workers’ compensation lifetime claims, and accident and health claims are not discounted and are based on (i) case basis estimates for losses reported on direct business, adjusted in the aggregate for ultimate loss expectations; (ii) estimates of incurred but not reported losses; (iii) estimates of losses on assumed reinsurance; (iv) estimates of future expenses to be incurred in the settlement of claims; (v) estimates of salvage and subrogation recoveries and (vi) estimates of amounts due from insureds related to losses under high deductible policies. Management considers current conditions and trends as well as past CNA and industry experience in establishing these estimates. The effects of inflation, which can be significant, are implicitly considered in the reserving process and are part of the recorded reserve balance. Ceded claim and claim adjustment expense reserves are reported as a component of Receivables on the Consolidated Balance Sheets.
Claim and claim adjustment expense reserves are presented net of anticipated amounts due from insureds related to losses under deductible policies of $1.4 billion as of December 31, 2011 and 2010. A significant portion of these amounts are supported by collateral. CNA also has an allowance for uncollectible deductible amounts, which is presented as a component of the allowance for doubtful accounts included in Receivables on the Consolidated Balance Sheets.
Structured settlements have been negotiated for certain property and casualty insurance claims. Structured settlements are agreements to provide fixed periodic payments to claimants. Certain structured settlements are funded by annuities purchased from Continental Assurance Company (“CAC”), a wholly owned and consolidated subsidiary of CNA, for which the related annuity obligations are reported in Future policy benefits reserves. Obligations for structured settlements not funded by annuities are included in claim and claim adjustment expense reserves and carried at present values determined using interest rates ranging from 5.5% to 8.0% at December 31,
2011 and 4.6% to 7.5% at December 31, 2010. At December 31, 2011 and 2010, the discounted reserves for unfunded structured settlements were $632 million and $713 million, net of discount of $1.1 billion in both periods.
Workers’ compensation lifetime claim reserves are calculated using mortality assumptions determined through statutory regulation and economic factors. Accident and health claim reserves are calculated using mortality and morbidity assumptions based on CNA and industry experience. Workers’ compensation lifetime claim reserves and accident and health claim reserves are discounted at interest rates ranging from 3.0% to 6.5% at both December 31, 2011 and 2010. At December 31, 2011 and 2010, such discounted reserves totaled $2.1 billion and $1.9 billion, net of discount of $520 million and $487 million.
Future policy benefits reserves - Reserves for long term care products and payout annuity contracts are computed using the net level premium method, which incorporates actuarial assumptions as to morbidity, mortality, persistency, discount rates, which are impacted by expected investment yields and expenses. Expense assumptions include the estimated effects of expenses to be incurred beyond the premium paying period. Actuarial assumptions generally vary by plan, age at issue and policy duration. The initial assumptions are determined at issuance, include a margin for adverse deviation, and are locked in throughout the life of the contract unless a premium deficiency develops. If a premium deficiency emerges, the assumptions are unlocked and deferred acquisition costs, if any, and the future policy benefit reserves are adjusted. Interest rates for long term care products range from 5.0% to 7.5% at December 31, 2011 and from 6.0% to 7.6% at December 31, 2010. Interest rates for payout annuity contracts range from 5.4% to 7.5% at December 31, 2011 and from 2.8% to 10.2% at December 31, 2010. In 2011, CNA unlocked assumptions related to its payout annuity contracts due to anticipated adverse changes in mortality and discount rates, which reflect the current low interest rate environment and CNA’s view of expected investment yields, resulting in loss recognition which increased insurance reserves by $166 million.
Policyholders’ funds reserves - Policyholders’ funds reserves primarily include reserves for investment contracts without life contingencies. For these contracts, policyholder liabilities are generally equal to the accumulated policy account values, which consist of an accumulation of deposit payments plus credited interest, less withdrawals and amounts assessed through the end of the period.
Guaranty fund and other insurance-related assessments - Liabilities for guaranty fund and other insurance-related assessments are accrued when an assessment is probable, when it can be reasonably estimated, and when the event obligating the entity to pay an imposed or probable assessment has occurred. Liabilities for guaranty funds and other insurance-related assessments are not discounted and are included as part of Other liabilities on the Consolidated Balance Sheets. As of December 31, 2011 and 2010, the liability balances were $152 million and $160 million. As of December 31, 2011 and 2010, included in Other assets on the Consolidated Balance Sheets were $2 million and $3 million of related assets for premium tax offsets. This asset is limited to the amount that is able to be offset against premium tax on future premium collections from business written or committed to be written.
Reinsurance - Reinsurance accounting allows for contractual cash flows to be reflected as premiums and losses. To qualify for reinsurance accounting, reinsurance agreements must include risk transfer. To meet risk transfer requirements, a reinsurance contract must include both insurance risk, consisting of underwriting and timing risk, and a reasonable possibility of a significant loss for the assuming entity.
Reinsurance receivables related to paid losses are presented at unpaid balances. Reinsurance receivables related to unpaid losses are estimated in a manner consistent with claim and claim adjustment expense reserves or future policy benefits reserves. Reinsurance receivables are reported net of an allowance for doubtful accounts on the Consolidated Balance Sheets. The cost of reinsurance is primarily accounted for over the life of the underlying reinsured policies using assumptions consistent with those used to account for the underlying policies or over the reinsurance contract period. The ceding of insurance does not discharge the primary liability of CNA.
CNA has established an allowance for doubtful accounts on reinsurance receivables which relates to both amounts already billed on ceded paid losses as well as ceded reserves that will be billed when losses are paid in the future. The allowance for doubtful accounts on reinsurance receivables is estimated on the basis of periodic evaluations of balances due from reinsurers, reinsurer solvency, management’s experience and current economic conditions. Reinsurer financial strength ratings are updated and reviewed on an annual basis or sooner if CNA becomes aware of significant changes related to a reinsurer. Because billed receivables are generally less than 5% of total
reinsurance receivables, the age of the reinsurance receivables related to paid losses is not a significant input into the allowance analysis. Changes in the allowance for doubtful accounts on reinsurance receivables are presented as a component of Insurance claims and policyholders’ benefits on the Consolidated Statements of Income.
Amounts are considered past due based on the reinsurance contract terms. Reinsurance receivables related to paid losses and any related allowance are written off after collection efforts have been exhausted or a negotiated settlement is reached with the reinsurer. Reinsurance receivables related to paid losses from insolvent insurers are written off when the settlement due from the estate can be reasonably estimated. At the time reinsurance receivables related to paid losses are written off, any required adjustment to reinsurance receivables related to unpaid losses is recorded as a component of Insurance claims and policyholders’ benefits on the Consolidated Statements of Income.
Reinsurance contracts that do not effectively transfer the economic risk of loss on the underlying policies are recorded using the deposit method of accounting, which requires that premium paid or received by the ceding company or assuming company be accounted for as a deposit asset or liability. CNA had $18 million and $23 million recorded as deposit assets at December 31, 2011 and 2010, and $123 million and $114 million recorded as deposit liabilities at December 31, 2011 and 2010. Income on reinsurance contracts accounted for under the deposit method is recognized using an effective yield based on the anticipated timing of payments and the remaining life of the contract. When the anticipated timing of payments changes, the effective yield is recalculated to reflect actual payments to date and the estimated timing of future payments. The deposit asset or liability is adjusted to the amount that would have existed had the new effective yield been applied since the inception of the contract.
Participating insurance - Policyholder dividends are accrued using an estimate of the amount to be paid based on underlying contractual obligations under policies and applicable state laws. Limitations exist on the amount of income from participating life insurance contracts that may be distributed to shareholders, and therefore the share of income on these policies that cannot be distributed to shareholders is excluded from Shareholders’ Equity by a charge to Income and Other comprehensive income and the establishment of a corresponding liability.
Deferred acquisition costs - Acquisition costs include commissions, premium taxes and certain underwriting and policy issuance costs which vary with and are related primarily to the acquisition of business. Such costs related to property and casualty business are deferred and amortized ratably over the period the related premiums are earned.
Deferred acquisition costs related to accident and health insurance are amortized over the premium-paying period of the related policies using assumptions consistent with those used for computing future policy benefit reserves for such contracts. Assumptions are made at the date of policy issuance or acquisition and are consistently applied during the lives of the contracts. Deviations from estimated experience are included in results of operations when they occur. For these contracts, the amortization period is typically the estimated life of the policy. At December 31, 2011, deferred acquisition costs were presented net of Shadow Adjustments of $412 million.
CNA evaluates deferred acquisition costs for recoverability. Anticipated investment income is considered in the determination of the recoverability of deferred acquisition costs. Adjustments, if necessary, are recorded in current results of operations. Deferred acquisition costs are presented net of ceding commissions and other ceded acquisition costs. Unamortized deferred acquisition costs relating to contracts that have been substantially changed by a modification in benefits, features, rights or coverages that were not anticipated in the original contract are not deferred and are included as a charge to operations in the period during which the contract modification occurred.
Investments in life settlement contracts and related revenue recognition - Prior to 2002, CNA purchased investments in life settlement contracts. A life settlement contract is a contract between the owner of a life insurance policy (the policy owner) and a third party investor (investor). Under a life settlement contract, CNA obtained the ownership and beneficiary rights of an underlying life insurance policy.
CNA accounts for its investments in life settlement contracts using the fair value method. Under the fair value method, each life settlement contract is carried at its fair value at the end of each reporting period. The change in fair value, life insurance proceeds received and periodic maintenance costs, such as premiums, necessary to keep the underlying policy in force, are recorded in Other revenues on the Consolidated Statements of Income. The fair value of CNA’s investments in life settlement contracts were $117 million and $129 million at December 31, 2011 and 2010, and are included in Other assets on the Consolidated Balance Sheets. The cash receipts and payments related
to life settlement contracts are included in Cash flows from operating activities on the Consolidated Statements of Cash Flows.
The following table details the values for life settlement contracts. The determination of fair value is discussed in Note 4.
CNA uses an actuarial model to estimate the aggregate face amount of life insurance that is expected to mature in each future year and the corresponding fair value. This model projects the likelihood of the insured’s death for each inforce policy based upon CNA’s estimated mortality rates, which may vary due to the relatively small size of the portfolio of life settlement contracts. The number of life settlement contracts presented in the table above is based upon the average face amount of inforce policies estimated to mature in each future year.
The increase in fair value recognized for the years ended December 31, 2011, 2010 and 2009 on contracts still being held was $5 million, $10 million and $10 million. The gains recognized during the years ended December 31, 2011, 2010 and 2009 on contracts that matured were $28 million, $19 million and $24 million.
Separate Account Business - Separate account assets and liabilities represent contract holder funds related to investment and annuity products for which the policyholder assumes substantially all the risk and reward. The assets are segregated into accounts with specific underlying investment objectives and are legally segregated from CNA. All assets of the separate account business are carried at fair value with an equal amount recorded for separate account liabilities. Fee income accruing to CNA related to separate accounts is primarily included within Other revenues on the Consolidated Statements of Income.
A number of separate account pension deposit contracts guarantee principal and an annual minimum rate of interest. If aggregate contract value in the separate account exceeds the fair value of the related assets, an additional Policyholders’ funds liability is established. During 2011, the CNA increased this pretax Policyholders’ funds liability by $18 million. CNA decreased this pretax Policyholders’ funds liability by $24 million and $42 million in 2010 and 2009. Certain of these contracts are subject to a fair value adjustment if terminated by the policyholder.
Goodwill - Goodwill represents the excess of purchase price over fair value of net assets of acquired entities. Goodwill is tested for impairment annually or when certain triggering events require additional tests. Accordingly, as a result of significant declines in natural gas prices, HighMount tested its goodwill for impairment at December 31, 2011 however, no impairment charge was required. Impairment losses, if any, are included in the Consolidated Statements of Income.
Property, plant and equipment - Property, plant and equipment is carried at cost less accumulated depreciation, depletion and amortization (“DD&A”). Depreciation is computed principally by the straight-line method over the estimated useful lives of the various classes of properties. Leaseholds and leasehold improvements are depreciated or amortized over the terms of the related leases (including optional renewal periods where appropriate) or the estimated lives of improvements, if less than the lease term.
The principal service lives used in computing provisions for depreciation are as follows:
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. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved natural gas and oil reserves, assuming an average price during the twelve month period adjusted for cash flow hedges in place, and limiting the classification of proved undeveloped reserves to locations scheduled to be drilled within five years. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent 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. Approximately 4.2% (unaudited) of HighMount’s total proved reserves as of December 31, 2011 are hedged by qualifying cash flow hedges, for which hedge adjusted prices were used to calculate estimated future net revenue. Future cash flows associated with settling asset retirement obligations that have been accrued in the Consolidated Balance Sheets are excluded from HighMount’s calculations of discounted cash flows under the full cost ceiling test.
Depletion of natural gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the base of costs subject to depletion also 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. The costs of investments in unproved properties including associated exploration-related costs are initially excluded from the depletable base. As the unproved properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over the terms of underlying leases. Once a property has been completely evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, proceeds from the sale or other disposition of natural gas and oil properties are accounted for as reductions of capitalized cost, unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case, a gain or loss is recognized.
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. Long-lived assets and intangibles with finite lives, under certain circumstances, are reported at the lower of carrying amount or fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.
Income taxes - The Company and its eligible subsidiaries file a consolidated tax return. Deferred income taxes are recognized for temporary differences between the financial statement and tax return bases of assets and liabilities, based on enacted tax rates and other provisions of the tax law. The effect of a change in tax laws or rates on deferred tax assets and liabilities is recognized in income in the period in which such change is enacted. 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 Company recognizes uncertain tax positions that it has taken or expects to take on a tax return. The tax benefit of a qualifying position is the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority having full knowledge of all relevant information. See Note 10 for additional information on the provision for income taxes.
Pension and postretirement benefits - The Company recognizes the overfunded or underfunded status of its defined benefit plans in Other assets or Other liabilities in the Consolidated Balance Sheets. Changes in funded status related to prior service costs and credits and actuarial gains and losses are recognized in the year in which the changes occur through Accumulated other comprehensive income (loss). The Company measures its benefit plan assets and obligations at December 31.
Stock based compensation - The Company records compensation expense upon issuance of share-based payment awards for all awards it grants, modifies, repurchases or cancels primarily on a straight-line basis over the requisite service period, generally four years. The share-based payment awards are valued using the Black-Scholes option pricing model. The application of this valuation model involves assumptions that are judgmental and highly sensitive in the valuation of these awards. These assumptions include the term that the awards are expected to be outstanding, an estimate of the volatility of the underlying stock price, applicable risk-free interest rates and the dividend yield of the Company’s stock.
The Company recognized compensation expense that decreased net income by $12 million for each of the years ended December 31, 2011, 2010 and 2009. Several of the Company’s subsidiaries also maintain their own stock option plans. The amounts reported above include the Company’s share of expense related to its subsidiaries’ plans.
Earnings Per Share - Companies with complex capital structures are required to present basic and diluted earnings per share. Basic earnings per share excludes dilution and is computed by dividing net income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.
For the years ended December 31, 2011, 2010 and 2009, approximately 0.8 million, 0.8 million and 0.6 million potential shares attributable to exercises under the Loews Corporation Stock Option Plan were included in the calculation of diluted earnings per share. For those same periods, approximately 2.0 million, 2.4 million and 3.4 million Stock Appreciation Rights (“SARs”) were not included in the calculation of diluted earnings per share due to the exercise price being greater than the average stock price.
Foreign currency - Foreign currency translation gains and losses are reflected in Shareholders’ equity as a component of Accumulated other comprehensive income (loss). The Company’s foreign subsidiaries’ balance sheet accounts are translated at the exchange rates in effect at each year end and income statement accounts are translated at the average exchange rates. Foreign currency transaction losses of $5 million, $18 million and $2 million were included in the Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009.
Regulatory accounting - FERC regulates the operations of Boardwalk Pipeline. GAAP for regulated entities requires Texas Gas Transmission, LLC (“Texas Gas”), a wholly owned subsidiary of Boardwalk Pipeline, to report certain assets and liabilities consistent with the economic effect of the manner in which independent third party regulators establish rates. Accordingly, certain costs and benefits are capitalized as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods.
Supplementary cash flow information - Cash payments made for interest on long term debt, net of capitalized interest, amounted to $526 million, $494 million and $442 million for the years ended December 31, 2011, 2010 and 2009. Cash payments for federal, foreign, state and local income taxes amounted to $322 million, $378 million and $219 million for the years ended December 31, 2011, 2010 and 2009. Investing activities exclude $14 million of accrued capital expenditures for the year ended December 31, 2011. For the years ended December 31, 2010 and 2009, investing activities include $51 million and $235 million of previously accrued capital expenditures.
Updated accounting guidance not yet adopted - In October of 2010, the FASB issued updated accounting guidance that limits the capitalization of costs incurred to acquire or renew insurance contracts to those that are incremental direct costs of successful contract acquisitions. The updated accounting guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 with prospective or retrospective application allowed. Effective January 1, 2012, the Company will adopt this updated accounting guidance retrospectively and estimates the cumulative effect as of December 31, 2011 will reduce shareholders’ equity by $63 million (after tax and noncontrolling interests).
Note 2. Acquisition/Divestitures
In November of 2011, CNA completed the sale of its 50% ownership interest in First Insurance Company of Hawaii (“FICOH”) and received $165 million in net proceeds. This sale did not have a significant impact on the Company’s results of operations.
On June 10, 2011, CNA completed the acquisition of all of the publicly traded shares of common stock of CNA Surety Corporation (“CNA Surety”). Prior to the acquisition, CNA owned approximately 61% of the outstanding common stock of CNA Surety. CNA Surety is now a wholly owned subsidiary of CNA. The aggregate purchase price was approximately $475 million. The amount paid to acquire the common shares of CNA Surety in excess of the closing date noncontrolling interests included in the Company’s equity of $438 million was reflected as an adjustment to Additional paid-in capital of $54 million. In addition, Accumulated other comprehensive income increased by $17 million related to the portion of net unrealized gains previously allocated to the noncontrolling shareholders. Net income attributable to the noncontrolling interests for the years ended December 31, 2011, 2010 and 2009 was not significant.
In December of 2011, Boardwalk HP Storage Company, LLC (“HP Storage”) acquired seven salt dome natural gas storage caverns and associated assets in Mississippi for approximately $550 million. HP Storage funded the acquisition with proceeds from a $200 million five year variable rate term loan and equity contributions from Boardwalk Pipelines Holding Corp. (“BPHC”) and Boardwalk Pipeline. BPHC, a wholly owned subsidiary of the Company, contributed $280 million for an 80% interest in HP Storage and Boardwalk Pipeline contributed $70 million for a 20% interest. HP Storage consolidated results are included in the Boardwalk Pipeline segment.
In the fourth quarter of 2011, HighMount acquired working interests in oil and gas properties located in Oklahoma. The oil and gas properties acquired are primarily undeveloped and HighMount believes that they contain oil and liquid reserves which can be produced through horizontal drilling. The purchase price was approximately $106 million in cash and is included primarily in the cost of unproved properties within Property, plant and equipment in the Consolidated Balance Sheets.
In the second quarter of 2010, HighMount completed the sale of substantially all exploration and production assets located in the Antrim Shale in Michigan and the Black Warrior Basin in Alabama for approximately $530 million. The Michigan and Alabama properties represented approximately 17% in aggregate of HighMount’s total proved reserves as of December 31, 2009. These sales did not have a material impact on the Consolidated Statements of Income. In accordance with the full cost method of accounting, proceeds from these sales were accounted for as reductions of capitalized costs.
Note 3. Investments
Net investment income is as follows:
(a)
Includes net unrealized gains (losses) related to changes in fair value on trading securities still held of $(58), $88 and $94 for the years ended December 31, 2011, 2010 and 2009.
As of December 31, 2011, the Company held nine non-income producing fixed maturity securities aggregating $3 million of fair value. As of December 31, 2010, the Company held seven non-income producing fixed maturity securities aggregating $3 million of fair value. As of December 31, 2011 and 2010, no investments in a single issuer exceeded 10% of shareholders’ equity other than investments in U.S. Treasury and obligations of government-sponsored enterprises.
Investment gains (losses) are as follows:
(a)
Includes gross realized gains of $299, $525 and $973 and gross realized losses of $322, $435 and $1,897 on available-for-sale securities for the years ended December 31, 2011, 2010 and 2009.
Net change in unrealized gains (losses) on available-for-sale investments is as follows:
The components of OTTI losses recognized in earnings by asset type are as follows:
A security is impaired if the fair value of the security is less than its cost adjusted for accretion, amortization and previously recorded OTTI losses, otherwise defined as an unrealized loss. When a security is impaired, the impairment is evaluated to determine whether it is temporary or other-than-temporary.
Significant judgment is required in the determination of whether an OTTI loss has occurred for a security. CNA follows a consistent and systematic process for determining and recording an OTTI loss. CNA has established a committee responsible for the OTTI process. This committee, referred to as the Impairment Committee, is made up of three officers appointed by CNA’s Chief Financial Officer. The Impairment Committee is responsible for evaluating all securities in an unrealized loss position on at least a quarterly basis.
The Impairment Committee’s assessment of whether an OTTI loss has occurred incorporates both quantitative and qualitative information. Fixed maturity securities that CNA intends to sell, or it more likely than not will be required to sell before recovery of amortized cost, are considered to be other-than-temporarily impaired and the entire difference between the amortized cost basis and fair value of the security is recognized as an OTTI loss in earnings. The remaining fixed maturity securities in an unrealized loss position are evaluated to determine if a credit loss exists. The factors considered by the Impairment Committee include: (i) the financial condition and near term prospects of the issuer, (ii) whether the debtor is current on interest and principal payments, (iii) credit ratings of the securities and (iv) general market conditions and industry or sector specific outlook. CNA also considers results and analysis of cash flow modeling for asset-backed securities, and when appropriate, other fixed maturity securities. The focus of the analysis for asset-backed securities is on assessing the sufficiency and quality of underlying collateral and timing of cash flows based on scenario tests. If the present value of the modeled expected cash flows equals or exceeds the amortized cost of a security, no credit loss is judged to exist and the asset-backed security is deemed to be temporarily impaired. If the present value of the expected cash flows is less than amortized cost, the security is judged to be other-than-temporarily impaired for credit reasons and that shortfall, referred to as the credit component, is recognized as an OTTI loss in earnings. The difference between the adjusted amortized cost basis and fair value, referred to as the non-credit component, is recognized as OTTI in Other comprehensive income. In subsequent reporting periods, a change in intent to sell or further credit impairment on a security whose fair value has not deteriorated will cause the non-credit component originally recorded as OTTI in Other comprehensive income to be recognized as an OTTI loss in earnings.
CNA performs the discounted cash flow analysis using stressed scenarios to determine future expectations regarding recoverability. For asset-backed securities, significant assumptions enter into these cash flow projections including delinquency rates, probable risk of default, loss severity upon a default, over collateralization and interest coverage triggers and credit support from lower level tranches.
CNA applies the same impairment model as described above for the majority of non-redeemable preferred stock securities on the basis that these securities possess characteristics similar to debt securities and that the issuers maintain their ability to pay dividends. For all other equity securities, in determining whether the security is other-than-temporarily impaired, the Impairment Committee considers a number of factors including, but not limited to: (i) the length of time and the extent to which the fair value has been less than amortized cost, (ii) the financial condition and near term prospects of the issuer, (iii) the intent and ability of CNA to retain its investment for a period of time sufficient to allow for an anticipated recovery in value and (iv) general market conditions and industry or sector specific outlook.
Prior to the adoption of the updated accounting guidance related to OTTI in the second quarter of 2009, CNA applied the impairment model described in the paragraph above to both fixed maturity and equity securities.
The amortized cost and fair values of securities are as follows:
The available-for-sale securities in a gross unrealized loss position are as follows:
The following table summarizes the activity for the years ended December 31, 2011 and 2010 and for the period from April 1, 2009 to December 31, 2009 related to the pretax credit loss component reflected in Retained earnings on fixed maturity securities still held at December 31, 2011, 2010 and 2009 for which a portion of an OTTI loss was recognized in Other comprehensive income.
Based on current facts and circumstances, the Company has determined that no additional OTTI losses related to the securities in an unrealized loss position presented in the table above are required to be recorded. A discussion of some of the factors reviewed in making that determination is presented below.
The classification between investment grade and non-investment grade presented in the discussion below is based on a ratings methodology that takes into account ratings from two major providers, Standard & Poor’s and Moody’s Investors Service, Inc. in that order of preference. If a security is not rated by these providers, the Company formulates an internal rating.
Corporate and Other Bonds
The unrealized losses on the Company’s investments in this category primarily relate to bonds within the financial industry sector. The financial industry sector holdings in this category include bonds with an aggregate fair value of $1.7 billion and an aggregate amortized cost of $1.8 billion as of December 31, 2011.
The corporate and other bonds in a gross unrealized loss position by ratings distribution are as follows:
The Company has no current intent to sell these securities, nor is it more likely than not that it will be required to sell prior to recovery of amortized cost. Additionally, the Company believes that the unrealized losses on these securities were not due to factors regarding the ultimate collection of principal and interest; accordingly, the Company has determined that there are no additional OTTI losses to be recorded at December 31, 2011.
States, Municipalities and Political Subdivisions
The unrealized losses on the Company’s investments in this category are primarily due to market conditions for zero coupon bonds, particularly for those with maturity dates that exceed 20 years. Yields for these securities continue to be higher than historical norms relative to after-tax returns on similar fixed income securities. Securities that comprise 83.1% of the gross unrealized losses in this category are rated AA or higher.
The largest exposures at December 31, 2011 as measured by gross unrealized losses were several separate issues of Puerto Rico sales tax revenue bonds with gross unrealized losses of $80 million. All of these securities are rated investment grade.
The Company has no current intent to sell these securities, nor is it more likely than not that it will be required to sell prior to recovery of amortized cost. Additionally, the Company believes that the unrealized losses on these securities were not due to factors regarding the ultimate collection of principal and interest; accordingly, the Company has determined that there are no additional OTTI losses to be recorded at December 31, 2011.
Asset-Backed Securities
The fair value of total asset-backed holdings at December 31, 2011 was $8.1 billion which was comprised of 2,011 different securities. The fair value of these securities tends to be influenced by the characteristics and projected cash flows of the underlying collateral rather than the credit of the issuer. Each security has deal-specific tranche structures, credit support that results from the unique deal structure, particular collateral characteristics and other distinct security terms. As a result, seemingly common factors such as delinquency rates and collateral performance affect each security differently. Of these securities, 112 had underlying collateral that was either considered sub-prime or Alt-A in nature. The exposure to sub-prime residential mortgage collateral and Alternative A residential mortgages that have lower than normal standards of loan documentation collateral is measured by the original deal structure.
The gross unrealized losses on residential mortgage-backed securities included $35 million related to securities guaranteed by a U.S. government agency or sponsored enterprise and $148 million related to non-agency structured securities. Non-agency structured securities included 131 securities that had at least one trade lot in a gross unrealized loss position and the aggregate severity of the gross unrealized loss was approximately 10.6% of amortized cost.
Commercial mortgage-backed securities included 61 securities that had at least one trade lot in a gross unrealized loss position. The aggregate severity of the gross unrealized loss was approximately 8.9% of amortized cost. Other asset-backed securities included 51 securities that had at least one trade lot in a gross unrealized loss position. The aggregate severity of the gross unrealized loss was approximately 1.0% of amortized cost.
The asset-backed securities in a gross unrealized loss position by ratings distribution are as follows:
The Company believes the unrealized losses are primarily attributable to broader economic conditions, changes in interest rates, wider than historical bid/ask spreads and uncertainty with regard to the timing and amount of ultimate collateral realization, but are not indicative of the ultimate collectibility of the current carrying values of the securities. The Company has no current intent to sell these securities, nor is it more likely than not that it will be required to sell prior to recovery of amortized cost; accordingly, the Company has determined that there are no additional OTTI losses to be recorded at December 31, 2011.
Contractual Maturity
The following table summarizes available-for-sale fixed maturity securities by contractual maturity at December 31, 2011 and 2010. Actual maturities may differ from contractual maturities because certain securities may be called or prepaid with or without call or prepayment penalties. Securities not due at a single date are allocated based on weighted average life.
Limited Partnerships
The carrying value of limited partnerships as of December 31, 2011 and 2010 was approximately $2.7 billion and $2.8 billion which includes undistributed earnings of $607 million and $812 million. Limited partnerships comprising 62.7% of the total carrying value are reported on a current basis through December 31, 2011 with no reporting lag, 23.0% are reported on a one month lag and the remainder are reported on more than a one month lag. As of December 31, 2011 and 2010, the Company had 83 and 84 active limited partnership investments. The number of limited partnerships held and the strategies employed provide diversification to the limited partnership portfolio and the overall invested asset portfolio.
Of the limited partnerships held, 84.1% and 87.4% at December 31, 2011 and 2010, employ hedge fund strategies that generate returns through investing in securities that are marketable while engaging in various management techniques primarily in public fixed income and equity markets. These hedge fund strategies include both long and short positions in fixed income, equity and derivative instruments. The hedge fund strategies may seek to generate gains from mispriced or undervalued securities, price differentials between securities, distressed investments, sector rotation, or various arbitrage disciplines. Within hedge fund strategies, approximately 41.4% were equity related, 39.5% pursued a multi-strategy approach, 15.2% were focused on distressed investments and 3.9% were fixed income related at December 31, 2011.
Limited partnerships representing 11.7% and 9.1% at December 31, 2011 and 2010 were invested in private debt and equity. The remaining were invested in various other partnerships including real estate. The ten largest limited partnership positions held totaled $1.3 billion and $1.4 billion as of December 31, 2011 and 2010. Based on the most recent information available regarding the Company’s percentage ownership of the individual limited partnerships, the carrying value reflected on the Consolidated Balance Sheets represents approximately 4.1% and 4.2% of the aggregate partnership equity at December 31, 2011 and 2010, and the related income reflected on the Consolidated Statements of Income represents 3.9%, 3.5% and 4.4% of the changes in partnership equity for all limited partnership investments for the years ended December 31, 2011, 2010 and 2009.
While the Company generally does not invest in highly leveraged partnerships, there are risks which may result in losses due to short-selling, derivatives or other speculative investment practices. The use of leverage increases volatility generated by the underlying investment strategies.
The Company’s limited partnership investments contain withdrawal provisions that generally limit liquidity for a period of thirty days up to one year and in some cases do not permit withdrawals until the termination of the partnership. Typically, withdrawals require advanced written notice of up to 90 days.
Investment Commitments
As of December 31, 2011, the Company had committed approximately $129 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships.
The Company invests in various privately placed debt securities, including bank loans, as part of its overall investment strategy and has committed to additional future purchases, sales and funding. The purchase and sale of these investments are recorded on the date that the legal agreements are finalized and cash settlements are made. As of December 31, 2011, the Company had commitments to purchase $95 million and sell $69 million of such investments. The Company has an obligation to fund additional amounts under the terms of current loan participations that may not be recorded until a draw is made. As of December 31, 2011, the Company had obligations on unfunded bank loan participations in the amount of $6 million.
As of December 31, 2011, the Company had mortgage loan commitments of $48 million representing signed loan applications received and accepted. The mortgage loans are recorded once funded.
Investments on Deposit
Securities with carrying values of approximately $3.5 billion and $2.9 billion were deposited by CNA’s insurance subsidiaries under requirements of regulatory authorities as of December 31, 2011 and 2010.
Cash and securities with carrying values of approximately $5 million and $6 million were deposited with financial institutions as collateral for letters of credit as of December 31, 2011 and 2010. In addition, cash and securities were deposited in trusts with financial institutions to secure reinsurance and other obligations with various third parties. The carrying values of these deposits were approximately $288 million and $298 million as of December 31, 2011 and 2010.
Note 4. Fair Value
Fair value is the price that would be received upon sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following fair value hierarchy is used in selecting inputs, with the highest priority given to Level 1, as these are the most transparent or reliable:
•
Level 1 - Quoted prices for identical instruments in active markets.
•
Level 2 - Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.
•
Level 3 - Valuations derived from valuation techniques in which one or more significant inputs are not observable.
Prices may fall within Level 1, 2 or 3 depending upon the methodologies and inputs used to estimate fair value for each specific security. In general, the Company seeks to price securities using third party pricing services. Securities not priced by pricing services are submitted to independent brokers for valuation and, if those are not available, internally developed pricing models are used to value assets using methodologies and inputs the Company believes market participants would use to value the assets.
The Company performs control procedures over information obtained from pricing services and brokers to ensure prices received represent a reasonable estimate of fair value and to confirm representations regarding whether inputs are observable or unobservable. Procedures include (i) the review of pricing service or broker pricing methodologies, (ii) back-testing, where past fair value estimates are compared to actual transactions executed in the market on similar dates, (iii) exception reporting, where changes in price, period-over-period, are reviewed and challenged with the pricing service or broker based on exception criteria, (iv) detailed analyses, where the Company independently validates information regarding inputs and assumptions for individual securities and (v) pricing validation, where prices received are compared to prices independently estimated by the Company.
The fair values of CNA’s life settlement contracts are included in Other assets. Equity options purchased are included in Equity securities, and all other derivative assets are included in Receivables. Derivative liabilities are included in Payable to brokers. Assets and liabilities measured at fair value on a recurring basis are summarized in the tables below:
The tables below present reconciliations for all assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2011 and 2010:
Net realized and unrealized gains and losses are reported in Net income as follows:
Major Category of Assets and Liabilities
Consolidated Statements of Income Line Items
Fixed maturity securities available-for-sale
Investment gains (losses)
Fixed maturity securities, trading
Net investment income
Equity securities available-for-sale
Investment gains (losses)
Equity securities, trading
Net investment income
Other invested assets
Investment gains (losses)
Derivative financial instruments held in a trading portfolio
Net investment income
Derivative financial instruments, other
Investment gains (losses) and Other revenues
Life settlement contracts
Other revenues
Securities shown in the Level 3 tables may be transferred in or out of Level 3 based on the availability of observable market information used to determine the fair value of the security. The availability of observable market information varies based on market conditions and trading volume and may cause securities to move in and out of Level 3 from reporting period to reporting period. There were no significant transfers between Level 1 and Level 2 during the years ended December 31, 2011 and 2010. The Company’s policy is to recognize transfers between levels at the beginning of quarterly reporting periods.
Valuation Methodologies and Inputs
The following section describes the valuation methodologies and relevant inputs used to measure different financial instruments at fair value, including an indication of the level in the fair value hierarchy in which the instruments are generally classified.
Fixed Maturity Securities
Fixed maturity securities are valued using methodologies that model information generated by market transactions involving identical or comparable assets, as well as discounted cash flow methodologies. Common inputs include: prices from recently executed transactions of similar securities, broker/dealer quotes, benchmark yields, spreads off benchmark yields, interest rates, and U.S. Treasury or swap curves. Specifically for asset-backed securities, key inputs include prepayment and default projections based on past performance of the underlying collateral and current market data.
Level 1 securities include highly liquid U.S. and foreign government bonds, and redeemable preferred stock, valued using quoted market prices. Level 2 securities include most other fixed maturity securities as the significant inputs are observable in the marketplace. Securities are generally assigned to Level 3 in cases where broker/dealer quotes are significant inputs to the valuation and there is a lack of transparency as to whether these quotes are based on information that is observable in the marketplace. Level 3 securities also include tax-exempt and taxable auction rate certificates. Fair value of auction rate securities is determined utilizing a pricing model with three primary inputs. The interest rate and spread inputs are observable from like instruments while the maturity date assumption is unobservable due to the uncertain nature of principal prepayments prior to maturity.
Equity Securities
Level 1 equity securities include publicly traded securities valued using quoted market prices. Level 2 securities are primarily non-redeemable preferred stocks and common stocks valued using pricing for similar securities, recently executed transactions, broker/dealer quotes and other pricing models utilizing observable inputs. Level 3 securities are priced using internal models with inputs that are not market observable.
Derivative Financial Instruments
Exchange traded derivatives are valued using quoted market prices and are classified within Level 1 of the fair value hierarchy. Level 2 derivatives include currency forwards valued using observable market forward rates. Over-the-counter derivatives, principally interest rate swaps, total return swaps, commodity swaps, credit default swaps, equity warrants and options, are valued using inputs including broker/dealer quotes and are classified within Level 2 or Level 3 of the valuation hierarchy, depending on the amount of transparency as to whether these quotes are based on information that is observable in the marketplace.
Short Term Investments
The valuation of securities that are actively traded or have quoted prices are classified as Level 1. These securities include money market funds and treasury bills. Level 2 primarily includes commercial paper, for which all inputs are market observable. Fixed maturity securities purchased within one year of maturity are classified consistent with fixed maturity securities discussed above.
Life Settlement Contracts
The fair values of life settlement contracts are determined as the present value of the anticipated death benefits less anticipated premium payments based on contract terms that are distinct for each insured, as well as CNA’s own assumptions for mortality, premium expense, and the rate of return that a buyer would require on the contracts, as no comparable market pricing data is available.
Separate Account Business
Separate account business includes fixed maturity securities, equities and short term investments. The valuation methodologies and inputs for these asset types have been described above.
Financial Assets and Liabilities Not Measured at Fair Value
The carrying amount and estimated fair value of the Company’s financial instrument assets and liabilities which are not measured at fair value on the Consolidated Balance Sheets are listed in the table below.
The following methods and assumptions were used in estimating the fair value of these financial assets and liabilities.
The fair values of Other invested assets were based on the present value of the expected future cash flows discounted at the current interest rate for similar financial instruments.
Premium deposits and annuity contracts were valued based on cash surrender values, estimated fair values or policyholder liabilities, net of amounts ceded related to sold business.
Fair value of debt was based on observable market prices when available. When observable market prices were not available, the fair value for debt was based on observable market prices of comparable instruments adjusted for differences between the observed instruments and the instruments being valued or is estimated using discounted cash flow analyses, based on current incremental borrowing rates for similar types of borrowing arrangements.
Note 5. Derivative Financial Instruments
The Company uses derivatives in the normal course of business, primarily in an attempt to reduce its exposure to market risk (principally interest rate risk, credit risk, equity price risk, commodity price risk and foreign currency risk) stemming from various assets and liabilities. The Company’s principal objective under such strategies is to achieve the desired reduction in economic risk, even if the position does not receive hedge accounting treatment.
The Company enters into interest rate swaps, futures and commitments to purchase securities to manage interest rate risk. Credit derivatives such as credit default swaps are entered into to modify the credit risk inherent in certain investments. Forward contracts, futures, swaps and options are used primarily to manage foreign currency and commodity price risk.
In addition to the derivatives used for risk management purposes described above, the Company may also use derivatives for purposes of income enhancement. Income enhancement transactions are entered into with the intention of providing additional income or yield to a particular portfolio segment or asset class. Income enhancement transactions include but are not limited to interest rate swaps, call options, put options, credit default swaps, index futures and foreign currency forwards.
Credit exposure associated with non-performance by the counterparties to derivative instruments is generally limited to the uncollateralized fair value of the asset related to the instruments recognized on the Consolidated Balance Sheets. The Company generally requires that all over-the-counter derivative contracts be governed by an International Swaps and Derivatives Association (“ISDA”) Master Agreement, and exchanges collateral under the terms of these agreements with its derivative investment counterparties depending on the amount of the exposure and the credit rating of the counterparty. The Company does not offset its net derivative positions against the fair value of the collateral provided. The fair value of collateral provided by the Company was $4 million and $2 million at December 31, 2011 and 2010 and consisted of cash and U.S. Treasury Bills. There was no collateral received from counterparties at December 31, 2011 compared to $1 million at December 31, 2010.
The agreements governing HighMount’s derivative instruments contain certain covenants, including a maximum total debt to capitalization ratio reviewed quarterly. If HighMount does not comply with these covenants, the counterparties to the derivative instruments could terminate the agreements and request payment on those derivative instruments in net liability positions. The aggregate fair value of HighMount’s derivative instruments that are in a liability position was $32 million at December 31, 2011. HighMount was not required to post any collateral under the governing agreements. At December 31, 2011, HighMount was in compliance with all of its covenants under the derivatives agreements.
See Note 4 for information regarding the fair value of derivative instruments.
A summary of the aggregate contractual or notional amounts and gross estimated fair values related to derivative financial instruments follows. Equity options purchased are included in Equity securities, and all other derivative assets are reported as Receivables. Derivative liabilities are included in Payable to brokers on the Consolidated Balance Sheets. The contractual or notional amounts for derivatives are used to calculate the exchange of contractual payments under the agreements and may not be representative of the potential for gain or loss on these instruments.
Derivatives without hedge designation - For derivatives not held in a trading portfolio, new derivative transactions entered into totaled approximately $359 million in notional value while derivative termination activity totaled approximately $262 million during the year ended December 31, 2011. The activity during the year ended December 31, 2011 was primarily attributable to interest rate swaps, forward commitments for mortgage-backed securities and foreign currency forwards. New derivative transactions entered into totaled approximately $1.2 billion in notional value while derivative termination activity totaled approximately $1.2 billion during the year ended December 31, 2010. The activity during the year ended December 31, 2010 was primarily attributable to interest rate futures and forward commitments for mortgaged-backed securities.
A summary of the recognized gains (losses) related to derivative financial instruments without hedge designation follows. Changes in the fair value of derivatives not held in a trading portfolio are reported in Investment gains (losses) and changes in the fair value of derivatives held for trading purposes are reported in Net investment income on the Consolidated Statements of Income.
Cash flow hedges - A significant portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of natural gas and other energy-related products. As of December 31, 2011, approximately 47.4 billion cubic feet of natural gas equivalents was hedged by qualifying cash flow hedges. The effective portion of these commodity hedges is reclassed from AOCI into earnings when the anticipated transaction affects earnings. Approximately 73% of these derivatives have settlement dates in 2012 and 27% have settlement dates in 2013. As of December 31, 2011, the estimated amount of net unrealized gains associated with commodity contracts that will be reclassified into earnings during the next twelve months was $29 million. However, these amounts are likely to vary materially as a result of changes in market conditions. Diamond Offshore uses foreign currency forward exchange contracts to reduce exposure to foreign currency losses on future foreign currency expenditures. The effective portion of these hedges is reclassified from AOCI into earnings when
the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. As of December 31, 2011, the estimated amount of net unrealized losses associated with these contracts that will be reclassified into earnings over the next twelve months was $7 million. The Company also uses interest rate swaps to hedge its exposure to variable interest rates or risk attributable to changes in interest rates on long term debt. The effective portion of the hedges is amortized to interest expense over the term of the related notes. As of December 31, 2011, the estimated amount of net unrealized losses associated with interest rate swaps that will be reclassified into earnings during the next twelve months was $4 million. However, this is likely to vary as a result of changes in LIBOR. For each of the years ended December 31, 2011, 2010, and 2009, the net amounts recognized due to ineffectiveness were less than $1 million.
In connection with HighMount refinancing its $1.1 billion variable rate term loans in 2011 a pretax loss of $34 million was recorded in Investment gains (losses) in the Consolidated Statements of Income for the year ended December 31, 2011, reflecting the reclassification of net derivative losses from AOCI to earnings. As a result of the sale of certain gas producing properties in 2010, HighMount recognized losses of $36 million in Investment gains (losses) in the Consolidated Statements of Income for the year ended December 31, 2010, reflecting the reclassification of net derivative losses from AOCI to earnings.
The following table summarizes the effective portion of the net derivative gains or losses included in OCI and the amount reclassified into Income for derivatives designated as cash flow hedges and for de-designated hedges:
Location of gain (loss) reclassified from AOCI into income:
Type of cash flow hedge
Consolidated Statements of Income line items
Commodities
Other revenues and Investment gains (losses)
Foreign exchange
Contract drilling expenses
Interest rate
Interest and Investment gains (losses)
Note 6. Receivables
Note 7. Property, Plant and Equipment
DD&A expense and capital expenditures are as follows:
Capitalized interest related to the construction and upgrade of qualifying assets amounted to approximately $31 million, $23 million and $29 million for the years ended December 31, 2011, 2010 and 2009.
Pipeline Equipment
In December of 2011, HP Storage acquired seven salt dome natural gas storage caverns and associated assets in Mississippi for $550 million of which $486 million was allocated to Pipeline equipment. See Note 2 for additional information related to this purchase.
Offshore Drilling Equipment
In 2011, Diamond Offshore recorded $490 million in Construction in process for three new, ultra-deepwater drillships with delivery expected in the second and fourth quarters of 2013 and in the second quarter of 2014. The total cost of the three drillships, including commissioning, spares and project management, is expected to be $1.8 billion.
In 2010, Diamond Offshore completed the sale of one of its high performance, premium jack-up drilling rigs, the Ocean Shield for a gross purchase price of $186 million and recognized a pretax gain of approximately $33 million.
Natural Gas and Oil Proved and Unproved Properties
Purchase of Assets
In the fourth quarter of 2011, HighMount paid $106 million to acquire working interests in oil and gas properties located in Oklahoma. See Note 2 for additional information related to this purchase.
Sale of Assets
In 2010, HighMount completed the sales of substantially all exploration and production assets located in the Antrim Shale in Michigan and in the Black Warrior Basin in Alabama for $530 million. In accordance with the full cost method of accounting, proceeds from these sales were accounted for as reductions of capitalized costs, and recorded as credits to Accumulated DD&A. See Note 2 for additional information related to these sales.
Impairment of Natural Gas and Oil Properties
At March 31, 2009, HighMount recorded a non-cash ceiling test impairment charge of $1.0 billion ($660 million after tax), related to its carrying value of natural gas and oil properties. The impairment was recorded as a credit to Accumulated DD&A. The write-down was the result of declines in commodity prices. Had the effects of HighMount’s cash flow hedges not been considered in calculating the ceiling limitation, the impairment would have been $1.2 billion ($784 million after tax) in 2009. No such impairment was required during 2010 and 2011.
Costs Not Being Amortized
HighMount excludes from amortization the cost of unproved properties, the cost of exploratory wells in progress and major development projects in progress. Natural gas and oil property and equipment costs not being amortized as of December 31, 2011, are as follows, by the year in which such costs were incurred:
Note 8. Claim and Claim Adjustment Expense Reserves
CNA’s property and casualty insurance claim and claim adjustment expense reserves represent the estimated amounts necessary to resolve all outstanding claims, including claims that are incurred but not reported (“IBNR”) as of the reporting date. CNA’s reserve projections are based primarily on detailed analysis of the facts in each case, CNA’s experience with similar cases and various historical development patterns. Consideration is given to such historical patterns as field reserving trends and claims settlement practices, loss payments, pending levels of unpaid claims and product mix, as well as court decisions, economic conditions including inflation and public attitudes. All of these factors can affect the estimation of claim and claim adjustment expense reserves.
Establishing claim and claim adjustment expense reserves, including claim and claim adjustment expense reserves for catastrophic events that have occurred, is an estimation process. Many factors can ultimately affect the final settlement of a claim and, therefore, the necessary reserve. Changes in the law, results of litigation, medical costs, the cost of repair materials and labor rates can all affect ultimate claim costs. In addition, time can be a critical part of reserving determinations since the longer the span between the incidence of a loss and the payment or settlement of the claim, the more variable the ultimate settlement amount can be. Accordingly, short-tail claims, such as property damage claims, tend to be more reasonably estimable than long-tail claims, such as workers’ compensation, general liability and professional liability claims. Adjustments to prior year reserve estimates, if necessary, are reflected in the results of operations in the period that the need for such adjustments is determined. There can be no assurance that CNA’s ultimate cost for insurance losses will not exceed current estimates.
Catastrophes are an inherent risk of the property and casualty insurance business and have contributed to material period-to-period fluctuations in CNA’s results of operations and/or equity. CNA reported catastrophe losses, net of reinsurance, of $222 million, $121 million and $89 million for the years ended December 31, 2011, 2010 and 2009. Catastrophe losses in 2011 related primarily to domestic storms, Hurricane Irene and the event in Japan.
The table below provides a reconciliation between beginning and ending claim and claim adjustment expense reserves, including claim and claim adjustment expense reserves of the life company:
(a) Total net incurred above does not agree to Insurance claims and policyholders’ benefits as reflected in the Consolidated Statements of Income due to amounts related to uncollectible reinsurance and loss deductible receivables, and benefit expenses related to future policy benefits and policyholders’ funds, which are not reflected in the table above.
The changes in provision for insured events of prior years (net prior year claim and claim adjustment expense reserve development) were as follows:
The following tables summarize the gross and net carried reserves:
A&EP Reserves
On August 31, 2010, Continental Casualty Company (“CCC”) together with several of CNA’s insurance subsidiaries completed a transaction with National Indemnity Company (“NICO”), a subsidiary of Berkshire Hathaway Inc., under which substantially all of CNA’s legacy A&EP liabilities were ceded to NICO (“Loss Portfolio Transfer”).
Under the terms of the NICO transaction, effective January 1, 2010 CNA ceded approximately $1.6 billion of net A&EP claim and allocated claim adjustment expense reserves to NICO under a retroactive reinsurance agreement with an aggregate limit of $4.0 billion. Included in the $1.6 billion of net A&EP claim and allocated claim
adjustment expense reserves was approximately $90 million of net claim and allocated claim adjustment expense reserves relating to CNA’s discontinued operations. The $1.6 billion of claim and allocated claim adjustment expense reserves ceded to NICO was net of $1.2 billion of ceded claim and allocated claim adjustment expense reserves under existing third party reinsurance contracts. The NICO aggregate reinsurance limit also covers credit risk on the existing third party reinsurance related to these liabilities.
CNA paid NICO a reinsurance premium of $2.0 billion and transferred to NICO billed third party reinsurance receivables related to A&EP claims with a net book value of $215 million (net of an allowance of $100 million for doubtful accounts on billed third party reinsurance receivables, as discussed further below). As of August 31, 2010, NICO deposited approximately $2.2 billion in a collateral trust account as security for its obligations to CNA. This $2.2 billion will be reduced by the amount of net A&EP claim and allocated claim adjustment expense payments. In addition, Berkshire Hathaway Inc. guaranteed the payment obligations of NICO up to the full aggregate reinsurance limit as well as certain of NICO’s performance obligations under the trust agreement. NICO is responsible for claims handling and billing and collection from third party reinsurers related to CNA’s A&EP claims.
The following table displays the impact of the Loss Portfolio Transfer on the 2010 Consolidated Statement of Income:
In connection with the transfer of billed third party reinsurance receivables related to A&EP claims and the coverage of credit risk afforded under the terms of the Loss Portfolio Transfer, CNA reduced its allowance for doubtful accounts on billed third party reinsurance receivables and ceded claim and allocated claim adjustment expense reserves by $200 million. This reduction is reflected in Other operating expenses presented above.
The gross A&EP claim and allocated claim adjustment expense reserves ceded under the Loss Portfolio Transfer and other existing third party reinsurance agreements was $2.3 billion and $2.5 billion at December 31, 2011 and 2010. The remaining amount available under the $4.0 billion aggregate limit of the Loss Portfolio Transfer was $2.3 billion on an incurred basis at December 31, 2011. These amounts include $138 million of adverse prior year development since the contract effective date of January 1, 2010. The net ultimate paid losses ceded under the Loss Portfolio Transfer were $351 million through December 31, 2011.
The Loss Portfolio Transfer is considered a retroactive reinsurance contract. In the event that the cumulative claim and allocated claim adjustment expenses ceded under the Loss Portfolio Transfer exceed the consideration paid, the resulting gain from such excess would be deferred. A cumulative amortization adjustment would be recognized in earnings in the period such excess arises so that the resulting deferred gain would reflect the balance that would have existed if the revised estimate was available at the inception date of the Loss Portfolio Transfer.
Net Prior Year Development
Changes in estimates of claim and allocated claim adjustment expense reserves and premium accruals, net of reinsurance, for prior years are defined as net prior year development. These changes can be favorable or unfavorable. The following tables and discussion include the net prior year development recorded for CNA Specialty, CNA Commercial and Other Insurance segments for the years ended December 31, 2011, 2010 and 2009. The net prior year development presented below includes premium development due to its direct relationship to claim and claim adjustment expense reserve development. The net prior year development presented below also includes the impact of commutations and write-offs, but excludes the impact of increases or decreases in the
allowance for doubtful accounts on reinsurance receivables. See Note 16 for further discussion of the allowance for doubtful accounts on reinsurance receivables.
Favorable net prior year development of $29 million, $2 million and $53 million was recorded in the Life & Group Non-Core segment for the years ended December 31, 2011, 2010 and 2009. Included in the 2009 favorable net prior year development is the impact of a settlement reached in 2009 with Willis Limited that resolved litigation related to the placement of personal accident reinsurance between 1997 and 1999. Under this settlement agreement, Willis Limited agreed to pay CNA a total of $130 million, which was reported as a loss recovery of $94 million, net of reinsurance.
For the year ended December 31, 2011, favorable premium development was recorded for CNA Specialty primarily due to changes in estimates of exposures in medical professional liability tail coverages. Unfavorable premium development for CNA Commercial was recorded due to a further reduction of ultimate premium estimates relating to retrospectively rated policies, partially offset by premium adjustments on auditable policies due to increased exposures.
For the year ended December 31, 2010, unfavorable premium development for CNA Commercial was recorded due to a change in ultimate premium estimates relating to retrospectively rated policies and return premium on auditable policies due to reduced exposures.
For the year ended December 31, 2009, unfavorable premium development for CNA Commercial was recorded due to changes in ultimate premium estimates relating to retrospectively rated policies, an estimated liability for an assessment related to a reinsurance association driven by large workers’ compensation policies, and less premium processing on auditable policies due to reduced exposures.
CNA Specialty
The following table and discussion provides further detail of the net prior year claim and allocated claim adjustment expense reserve development recorded for the CNA Specialty segment:
Favorable development for medical professional liability was primarily due to favorable case incurred emergence in nurses, physicians, excess institutions and primary institutions in accident years 2008 and prior.
Favorable development for other professional liability was driven by better than expected loss emergence in the life agents, accountants, and architects & engineers business in accident years 2008 and prior. In addition, favorable development in CNA’s European book of business was primarily due to favorable outcomes on several large losses in financial directors and officers (“D&O”) and errors and omissions (“E&O”) coverages in accident years 2003 and prior.
Favorable development for surety coverages was primarily due to a decrease in the estimated loss on a large national contractor in accident year 2005 and better than expected loss emergence in accident years 2009 and prior.
Favorable development in warranty was driven by favorable policy year experience on an aggregate stop loss policy covering CNA’s non-insurance warranty subsidiary.
Other includes standard property and casualty coverages provided to CNA Specialty customers. Unfavorable development for other coverages was primarily due to increased frequency of large claims in auto and workers’ compensation coverages in accident years 2009 and 2010.
Overall, favorable development for medical professional liability was primarily due to lower than expected frequency of large losses, primarily in accident years 2007 and prior. This development amount also included unfavorable development in accident years 2008 and 2009 due to increased frequency of large losses related to medical products.
Overall, favorable development for other professional liability was recorded primarily in accident years 2007 and prior in D&O and E&O coverages due to several factors, including reduced frequency of large claims and the result of reviews of large claims. This development amount also included unfavorable development in employment practices liability, E&O and D&O coverages recorded in accident years 2008 and 2009, driven by the economic recession and higher unemployment.
Favorable development for surety coverages was primarily due to a decrease in the estimated loss on a large national contractor in accident year 2005 and lower than expected claim emergence in accident years 2008 and prior.
Favorable development for medical professional liability was primarily due to better than expected frequency and severity in accident years 2005 and prior, including claims closing favorable to expectations and favorable changes on individually reviewed accounts.
Favorable development for other professional liability was primarily in financial institutions, accountants and lawyers, D&O and life agents coverages. For financial institutions, favorable development was due to favorable experience on a number of large claims in accident years 2003 and prior and decreased frequency of large claims in accident years 2007 and prior. Favorable development in accountants and lawyers was due to better than expected large claim frequency in accident years 2004 through 2006. Favorable development in D&O and life agents coverages was due to lower than expected large claim frequency. Additionally, favorable development in CNA’s European book of business was primarily due to favorable emergence relative to expectations in non-financial D&O and E&O coverages.
Favorable development for surety coverages was driven by claim activity substantially below expectations, primarily in accident years 2004 through 2007.
CNA Commercial
The following table and discussion provides further detail of the net prior year claim and allocated claim adjustment expense reserve development recorded for the CNA Commercial segment:
Favorable development for commercial auto coverages was due to lower than expected severity on bodily injury claims and favorable claim emergence on umbrella policies in accident years 2006 and prior.
Favorable development in the general liability coverages was primarily due to favorable claim emergence in accident years 2007 and prior related to both primary and umbrella liability coverages.
Unfavorable development for workers’ compensation was related to increased medical severity in accident year 2010.
Overall, favorable development for property and other coverages was due to decreased frequency of large losses in commercial multi-peril coverages primarily in accident year 2010, favorable loss emergence related to catastrophe claims in accident year 2008 and favorable loss emergence related to non-catastrophe claims in accident years 2010 and prior. This development amount also included unfavorable development related to unallocated claim adjustment expenses.
Favorable development for commercial auto coverages was primarily due to lower than expected frequency and severity trends in accident years 2009 and prior.
Overall, favorable development for general liability and umbrella coverages was primarily due to better than expected loss emergence in accident years 2006 and prior. This development amount also included unfavorable development, primarily driven by increased claim frequency in accident years 2004 and prior for excess workers’ compensation and in accident years 2008 and 2009 for a portion of CNA’s primary casualty surplus lines book. Unfavorable development was also recorded for accident years prior to 2001 related to mass tort claims, primarily as a result of increased defense costs on specific mass tort accounts, including amounts related to unallocated claim adjustment expenses.
Unfavorable development in workers’ compensation was related to increased severity of indemnity losses relative to expectations on claims related to Defense Base Act contractors, primarily in accident years 2008 and prior.
Favorable development was recorded for property and marine coverages. Favorable development on catastrophe claims was due to lower than expected incurred loss emergence, primarily in accident years 2008 and 2009. Favorable non-catastrophe development was due to lower than expected severity in accident years 2009 and prior. Favorable development in marine business was primarily due to decreased claim frequency and favorable cargo salvage recoveries in recent accident years as well as lower than expected severity for excess liability in accident years 2005 and prior. Favorable property and marine development in CNA’s European operation was due to lower than expected frequency of large claims primarily in accident year 2009.
Favorable development was recorded in auto coverages, primarily driven by decreased frequency in CNA’s Hawaiian book of business.
Overall, favorable development was recorded for general liability coverages. Favorable development in construction defect exposures was due to decreased frequency and severity trends in accident years 2003 and prior. Favorable development in non-construction defect exposures was primarily due to claims closing favorable to expectations in accident years 2006 and prior. Favorable development in CNA’s Canadian casualty programs was primarily driven by severity emerging favorable to prior expectations. This development amount also included unfavorable development recorded due to higher than anticipated litigation costs related to mass tort exposures, primarily in accident years 1997 and prior.
Unfavorable workers’ compensation development was due to increased paid and incurred severity primarily in the small and middle markets businesses in accident years 2004, 2007 and 2008. Unfavorable development was recorded related to increased severity of indemnity losses relative to expectations on workers’ compensation claims related to Defense Base Act contractors primarily in accident years 2004 through 2008.
Favorable development was recorded for property coverages. Favorable catastrophe development was driven by the favorable settlement of several claims primarily in accident years 2005 and 2007, and better than expected frequency and severity on claims in accident year 2008. Favorable non-catastrophe development primarily related to large property and marine coverages in accident years 2007 and 2008. Favorable development was recorded in CNA’s European property, cargo, and personal accident and travel businesses driven by both frequency and severity emerging favorably to prior expectations, particularly in accident years 2007 and 2008.
Other Insurance
Unfavorable development was recorded related to asbestos. CNA noted adverse development in various asbestos accounts due to increases in average claim severity and defense expense arising from increased trial activity. Additionally, CNA had not seen a decline in the overall emergence of new accounts.
Unfavorable development was recorded related to environmental pollution. CNA noted adverse development in various pollution accounts due to changes in the liabilities attributed to its policyholders and adverse changes in case law impacting insurers’ coverage obligations. These changes in turn increased CNA’s account estimates on certain accounts. In addition, the frequency of environmental pollution claims did not decline at the rate previously anticipated.
Note 9. Leases
Leases cover office facilities, machinery and computer equipment. The Company’s hotels in some instances are constructed on leased land. Rent expense amounted to $91 million, $92 million and $95 million for the years ended December 31, 2011, 2010 and 2009. The table below presents the future minimum lease payments to be made under non-cancelable operating leases along with lease and sublease minimum receipts to be received on owned and leased properties.
Note 10. Income Taxes
The Company and its eligible subsidiaries file a consolidated federal income tax return. The Company has entered into a separate tax allocation agreement with CNA, a majority-owned subsidiary in which its ownership exceeds 80%. The agreement provides that the Company will: (i) pay to CNA the amount, if any, by which the Company’s consolidated federal income tax is reduced by virtue of inclusion of CNA in the Company’s return, or (ii) be paid by CNA an amount, if any, equal to the federal income tax that would have been payable by CNA if it had filed a separate consolidated return. The agreement may be canceled by either of the parties upon thirty days written notice.
For 2009 through 2011, the Company has participated in the Compliance Assurance Process (“CAP”), which is a voluntary program for a limited number of large corporations. Under CAP, the Internal Revenue Service (“IRS”) conducts a real-time audit and works contemporaneously with the Company to resolve any issues prior to the filing of the tax return. The Company believes this approach should reduce tax-related uncertainties, if any. Although the outcome of tax audits is always uncertain, the Company believes that any adjustments resulting from audits will not have a material impact on its results of operations, financial position and cash flows. The Company and/or its subsidiaries also file income tax returns in various state, local and foreign jurisdictions. These returns, with few exceptions, are no longer subject to examination by the various taxing authorities before 2007.
Diamond Offshore, which is not included in the Company’s consolidated federal income tax return, files income tax returns in the U.S. federal, various state and foreign jurisdictions. Diamond Offshore’s 2009 and 2010 U.S. federal income tax returns remain subject to examination. Tax years that remain subject to examination by the various other jurisdictions include years 2003 to 2010.
The current and deferred components of income tax expense (benefit), excluding taxes on discontinued operations, are as follows:
The components of U.S. and foreign income before income tax and a reconciliation between the federal income tax expense at statutory rates and the actual income tax expense is as follows:
(a) Includes state and local taxes, adjustments to prior year estimates and other non-deductible expenses.
Provision has been made for the expected U.S. federal income tax liabilities applicable to undistributed earnings of subsidiaries, except for certain subsidiaries for which the Company intends to invest the undistributed earnings indefinitely, or recover such undistributed earnings tax-free. Except for certain foreign sourced activities which Diamond Offshore plans to distribute, it is Diamond Offshore’s intention to indefinitely reinvest future earnings of the subsidiary to finance foreign activities. At December 31, 2011, the Company is not required to provide deferred taxes on undistributed earnings related to a domestic affiliate. The determination of the amount of the unrecognized deferred tax liability related to the undistributed earnings of foreign subsidiaries is not practicable.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
At December 31, 2011 and 2010, there were $41 million and $46 million of tax benefits related to Diamond Offshore that if recognized would affect the effective rate.
The Company recognizes interest accrued related to: (i) unrecognized tax benefits in Interest expense and (ii) tax refund claims in Other revenues on the Consolidated Statements of Income. The Company recognizes penalties in Income tax expense on the Consolidated Statements of Income. Penalties and interest amounts recorded by the Company were insignificant for the years ended December 31, 2011, 2010 and 2009.
The following table summarizes deferred tax assets and liabilities:
Amounts recognized in the Consolidated Balance Sheets consist of:
As of December 31, 2011, the Company has federal loss carryforwards with a tax effect of approximately $29 million which expire in 2014 and 2030 and federal tax credit carryforwards of $68 million, of which $63 million expire between 2019 and 2021. Diamond Offshore has foreign operating loss carryforwards with a tax effect of approximately $27 million, of which $8 million have an indefinite life with the remaining benefits expiring between 2014 and 2021.
Although realization of deferred tax assets is not assured, management believes it is more likely than not that the recognized deferred tax assets will be realized through recoupment of ordinary and capital taxes paid in prior carryback years and through future earnings, reversal of existing temporary differences and available tax planning strategies.
Note 11. Debt
CNA has a $250 million credit agreement with a syndicate of banks and other lenders. The credit agreement term extends to August 1, 2012 and is intended to be used for general corporate purposes. Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus CNA’s credit risk spread. Under the credit agreement, CNA is required to pay certain fees, including a facility fee and a utilization fee, both of which would adjust automatically in the event of a change in CNA’s financial ratings. The credit agreement includes covenants regarding maintenance of a minimum consolidated net worth and a specified ratio of consolidated indebtedness to consolidated total capitalization. There is no outstanding amount due under this credit agreement as of December 31, 2011, leaving the full limit of $250 million available as of December 31, 2011. CNA’s remaining debt obligations contain customary covenants for investment grade insurers. As of December 31, 2011, CNA was in compliance with all covenants.
In February of 2011, CNA issued $400 million aggregate principal amount of 5.75% ten-year senior notes due August 15, 2021. CNA used the net proceeds to redeem the outstanding $400 million aggregate principal amount of its 6.0% senior notes due in 2011 plus required interest and payments.
In November of 2011, CNA redeemed the outstanding $31 million plus accrued and unpaid interest of the CNA Surety debenture originally due April 29, 2034.
In December of 2011, HighMount entered into a credit agreement with a syndicate of banks for a $600 million variable rate term loan and a $250 million revolving credit facility. The credit agreement is for a period of five years and bears interest at LIBOR plus an applicable margin. As of December 31, 2011, HighMount had $100 million outstanding under the revolving credit facility. The proceeds from the loan plus $400 million of cash received from the Company were utilized to repay the $1.1 billion of variable rate term loans due in July 2012.
HighMount has entered into interest rate swaps for a notional amount of $300 million to hedge its exposure to fluctuations in LIBOR. These swaps effectively fix the interest rate on the hedged portion of the term loan to 1.1% plus an applicable margin. Among other customary covenants, HighMount must meet a maximum predetermined total debt to capitalization ratio and a minimum present value of proved natural gas and oil reserves to total debt ratio. At December 31, 2011, HighMount was in compliance with all of its debt covenants under the credit agreement.
Boardwalk Pipeline maintains a $950 million revolving credit facility under which Boardwalk Pipeline and its operating subsidiaries each may borrow funds, up to applicable sub-limits. Borrowings under the credit facility bear interest at a rate per annum equal to at its election, either; (i) the higher of the prime rate or the Federal funds rate plus 50 basis points or (ii) LIBOR plus an applicable margin. Among other customary covenants, each of the borrowers must maintain a minimum ratio, as of the last day of each fiscal quarter, of consolidated total debt to consolidated earnings before interest, income taxes and depreciation and amortization (as defined in the agreement), measured for the preceding twelve months, of not more than five to one.
As of December 31, 2011, Boardwalk Pipeline had $458 million of loans outstanding under its revolving credit facility with a weighted-average interest rate on the borrowings of 0.5% and had no letters of credit issued. The revolving credit facility has a maturity date of June 29, 2012, however, all outstanding revolving loans on such date may be converted to term loans having a maturity date of June 29, 2013. As of December 31, 2011, Boardwalk Pipeline and its operating subsidiaries were in compliance with all covenant requirements under the credit facility.
In January and June of 2011, Boardwalk Pipeline issued $325 million and $115 million aggregate principal amount of 4.5% senior notes due February 1, 2021. The net proceeds of the offerings were used to reduce borrowings under the revolving credit facility and redeem 5.5% Notes due April 1, 2013.
In December of 2011, HP Storage entered into a credit agreement for a $200 million variable rate term loan due December 1, 2016. The loan bears interest at the Eurodollar rate plus an applicable margin and contains customary covenants including specified leveraged ratios. The proceeds from the loan were utilized to fund the acquisition of HP Storage. As of December 31, 2011, HP Storage was in compliance with all covenants under the credit agreement.
At December 31, 2011, the aggregate of long term debt maturing in each of the next five years is approximately as follows: $88 million in 2012, $689 million in 2013, $819 million in 2014, $948 million in 2015, $1.9 billion in 2016 and $4.6 billion thereafter. Long term debt is generally redeemable in whole or in part at the greater of the
principal amount or the net present value of scheduled payments discounted at the specified treasury rate plus a margin.
Note 12. Shareholders’ Equity
The components of Accumulated other comprehensive income (loss) are as follows:
Subsidiary Equity Transactions
In June of 2011, Boardwalk Pipeline sold 6 million common units at a price of $29.33 per unit in a public offering and received net proceeds of $174 million, including a $4 million contribution by the Company to maintain its 2% general partner interest. The Company’s percentage ownership interest in Boardwalk Pipeline declined as a result of this transaction, from 66% to 64%. The issuance price of the common units exceeded the Company’s carrying amount, resulting in an increase to additional paid-in capital of $28 million.
In the first quarter of 2012, Boardwalk Pipeline sold 9.2 million common units at a price of $27.55 per unit in a public offering and received net proceeds of $250 million, including a $5 million contribution by the Company to maintain its 2% general partner interest. The Company’s percentage ownership interest in Boardwalk Pipeline declined as a result of this transaction, from 64% to 61%. The Company will record an increase to additional paid-in capital in the first quarter of 2012 of approximately $40 million.
Treasury Share Repurchases
The Company repurchased 18.2 million, 11.0 million and 10.5 million shares of Loews common stock at aggregate costs of $718 million, $405 million and $348 million during the years ended December 31, 2011, 2010 and 2009. Upon retirement, treasury stock is eliminated through a reduction to common stock, additional paid-in capital and retained earnings.
Note 13. Statutory Accounting Practices (Unaudited)
CNA’s domestic insurance subsidiaries maintain their accounts in conformity with accounting practices prescribed or permitted by insurance regulatory authorities, which vary in certain respects from GAAP. In converting from statutory accounting principles to GAAP, the more significant adjustments include deferral of policy acquisition costs and the inclusion of net unrealized holding gains or losses in shareholders’ equity relating to certain fixed maturity securities.
CNA’s insurance subsidiaries are domiciled in various jurisdictions. These subsidiaries prepare statutory financial statements in accordance with accounting practices prescribed or permitted by the respective jurisdictions’ insurance regulators. Domestic prescribed statutory accounting practices are set forth in a variety of publications of the National Association of Insurance Commissioners (“NAIC”) as well as state laws, regulations and general administrative rules.
CNA’s ability to pay dividends and other credit obligations is significantly dependent on receipt of dividends from its subsidiaries. The payment of dividends to CNA by its insurance subsidiaries without prior approval of the insurance department of each subsidiary’s domiciliary jurisdiction is limited by formula. Dividends in excess of these amounts are subject to prior approval by the respective state insurance departments.
Dividends from CCC are subject to the insurance holding company laws of the State of Illinois, the domiciliary state of CCC. Under these laws, ordinary dividends, or dividends that do not require prior approval by the Department, may be paid only from earned surplus, which is calculated by removing unrealized gains from unassigned surplus. As of December 31, 2011, CCC is in a positive earned surplus position, enabling CCC to pay approximately $990 million of dividend payments during 2012 that would not be subject to the Department’s prior approval. The actual level of dividends paid in any year is determined after an assessment of available dividend capacity, holding company liquidity and cash needs as well as the impact the dividends will have on the statutory surplus of the applicable insurance company.
CNA’s domestic insurance subsidiaries are subject to risk-based capital requirements. Risk-based capital is a method developed by the NAIC to determine the minimum amount of statutory capital appropriate for an insurance company to support its overall business operations in consideration of its size and risk profile. The formula for determining the amount of risk-based capital specifies various factors, weighted based on the perceived degree of risk, which are applied to certain financial balances and financial activity. The adequacy of a company’s actual capital is evaluated by a comparison to the risk-based capital results, as determined by the formula. Companies below minimum risk-based capital requirements are classified within certain levels, each of which requires specified
corrective action. As of December 31, 2011 and 2010, all of CNA’s domestic insurance subsidiaries exceeded the minimum risk-based capital requirements.
Subsidiaries with insurance operations outside the United States are also subject to insurance regulation in the countries in which they operate. CNA has legal entity and branch operations in other countries, primarily the United Kingdom, Canada and Bermuda. CNA’s foreign legal entities and branch met or exceeded regulatory capital requirements.
Combined statutory capital and surplus and net income (loss), determined in accordance with accounting practices prescribed or permitted by insurance regulatory authorities for the Combined Continental Casualty Companies and the life company, were as follows:
(a) Represents the combined statutory surplus of CCC and its subsidiaries, including the Life company.
(b) Preliminary.
Note 14. Supplemental Natural Gas and Oil Information (Unaudited)
Users of this information should be aware that the process of estimating quantities of proved natural gas, NGLs and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent 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 are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods.
Estimates of reserves as of December 31, 2011, 2010 and 2009 are based upon studies for each of HighMount’s 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. HighMount’s reserve estimates for 2011 were audited by Netherland, Sewell & Associates, Inc., (“NSAI”). NSAI is an independent third party petroleum engineering consulting firm, and the audit was performed in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. All proved reserves are located in the United States of America.
Reserves
Estimated net quantities of proved natural gas and oil (including condensate and NGLs) reserves at December 31, 2011, 2010 and 2009 and changes in the reserves during 2011, 2010 and 2009 are shown in the schedule below:
(a) The 2009 revision is primarily attributable to lower 2009 average prices as compared to December 31, 2008. The lower 2009 average prices caused the reclassification of some proven undeveloped reserves.
(b) HighMount added 238 Bcfe of proved undeveloped reserves from non-proved categories in 2010. These additions pertain to locations HighMount expects to drill during the next five years. Additionally, HighMount added 42 Bcfe primarily through drilling and the remaining 51 Bcfe in additions were associated with the Alabama and Michigan properties prior to sale.
(c) During 2010, HighMount reclassified 208 Bcfe of proved undeveloped reserves to a non-proved category due to certain wells reaching their five year maturity as a result of reduced drilling activity in 2009 and 2010. Additionally, HighMount reduced its proved developed and proved undeveloped reserves by 346 Bcfe as a result of higher production declines on its producing wells than previously anticipated.
(d) During 2011, HighMount reduced its proved developed and proved undeveloped reserves by 152 Bcfe as a result of recent higher decline rates of producing wells and economic factors such as lower gas prices and higher operating expenses.
Capitalized Costs
The aggregate amounts of costs capitalized for natural gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:
The following costs were incurred in natural gas and oil producing activities:
(a) Development costs incurred for proved undeveloped reserves were $25, $23 and $27 in 2011, 2010 and 2009.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves
The following table represents a calculation of the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities that HighMount owns:
(a) 2011, 2010 and 2009 amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year end.
(b) The following prices were used in the determination of standardized measure:
In the foregoing determination of future cash inflows, sales prices for natural gas and oil represent average prices determined as an unweighted arithmetic average of the first-day-of-the-month price for each month, changed for contractual arrangements with customers. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of HighMount’s proved reserves. HighMount cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate. In addition, costs and prices as of the measurement date are used in the determinations, and no value was assigned to probable or possible reserves.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves
The following table is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:
Note 15. Benefit Plans
Pension Plans - The Company has several non-contributory defined benefit plans for eligible employees. Benefits for certain plans are determined annually based on a specified percentage of annual earnings (based on the participant’s age or years of service) and a specified interest rate (which is established annually for all participants) applied to accrued balances. The benefits for another plan which covers salaried employees are based on formulas which include, among others, years of service and average pay. The Company’s funding policy is to make contributions in accordance with applicable governmental regulatory requirements.
Other Postretirement Benefit Plans - The Company has several postretirement benefit plans covering eligible employees and retirees. Participants generally become eligible after reaching age 55 with required years of service. Actual requirements for coverage vary by plan. Benefits for retirees who were covered by bargaining units vary by each unit and contract. Benefits for certain retirees are in the form of a Company health care account.
Benefits for retirees reaching age 65 are generally integrated with Medicare. Other retirees, based on plan provisions, must use Medicare as their primary coverage, with the Company reimbursing a portion of the unpaid amount; or are reimbursed for the Medicare Part B premium or have no Company coverage. The benefits provided by the Company are basically health and, for certain retirees, life insurance type benefits.
In November of 2010, CNA changed a postretirement benefit that resulted in a plan amendment. The effect of this change was a reduction to the accumulated postretirement benefit obligation of $60 million at December 31, 2010.
The Company funds certain of these benefit plans, and accrues postretirement benefits during the active service of those employees who would become eligible for such benefits when they retire. The Company uses December 31 as the measurement date for its plans.
Weighted-average assumptions used to determine benefit obligations:
Weighted-average assumptions used to determine net periodic benefit cost:
The expected long term rate of return for plan assets is determined based on widely-accepted capital market principles, long term return analysis for global fixed income and equity markets as well as the active total return oriented portfolio management style. Long term trends are evaluated relative to market factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of diversification needs and rebalancing is maintained.
Assumed health care cost trend rates:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. An increase or decrease in the assumed health care cost trend rate of 1% in each year would not have a significant impact on the Company’s service and interest cost as of December 31, 2011. An increase of 1% in each year would increase the Company’s accumulated postretirement benefit obligation as of December 31, 2011 by $2 million and a decrease of 1% in each year would decrease the Company’s accumulated postretirement benefit obligation as of December 31, 2011 by $5 million.
Net periodic benefit cost components:
The following provides a reconciliation of benefit obligations:
The accumulated benefit obligation for all defined benefit pension plans was $3.3 billion and $3.0 billion at December 31, 2011 and 2010.
The Company employs a total return approach whereby a mix of equity and fixed maturity securities are used to maximize the long term return of plan assets for a prudent level of risk and to manage cash flows according to plan requirements. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established after careful consideration of the plan liabilities, plan funded status and corporate financial conditions. The investment portfolio contains a diversified blend of fixed maturity, equity and short term securities. Alternative investments, including limited partnerships, are used to enhance risk adjusted long term returns while improving portfolio diversification. At December 31, 2011, the Company had committed $30 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships. Investment risk is monitored through annual liability measurements, periodic asset/liability studies and quarterly investment portfolio reviews.
The table below presents the estimated amounts to be recognized from Accumulated other comprehensive income into net periodic cost (benefit) during 2012.
The table below presents the estimated future minimum benefit payments at December 31, 2011.
In 2012, it is expected that contributions of approximately $107 million will be made to pension plans and $7 million to postretirement health care and life insurance benefit plans.
Pension plan assets measured at fair value on a recurring basis are summarized below.
The limited partnership investments are recorded at fair value, which represents the plans’ share of the net asset value of each partnership, as determined by the General Partner. Level 2 includes limited partnership investments which can be redeemed at net asset value in 90 days or less. Level 3 includes limited partnership investments with withdrawal provisions greater than 90 days, or for which withdrawals are not permitted until the termination of the partnership. Within hedge fund strategies, approximately 54% are equity related, 35% pursue a multi-strategy approach, 10% are focused on distressed investments and 1% are fixed income related at December 31, 2011.
The fair value of the guaranteed investment contracts is an estimate of the amount that would be received in an orderly sale to a market participant at the measurement date. The amount the plan would receive from the contract holder if the contracts were terminated is the primary input and is unobservable. The guaranteed investment contracts are therefore classified as Level 3 investments.
For a discussion of the valuation methodologies used to measure fixed maturity securities, equities and short term investments, see Note 4.
The tables below present reconciliations for all pension plan assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2011 and 2010:
Other postretirement benefits plan assets measured at fair value on a recurring basis are summarized below.
The table below presents reconciliations for all Other postretirement benefit plan assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the year ended December 31, 2010. There were no Level 3 assets at December 31, 2011.
Savings Plans - The Company and its subsidiaries have several contributory savings plans which allow employees to make regular contributions based upon a percentage of their salaries. Matching contributions are made up to specified percentages of employees’ contributions. The contributions by the Company and its subsidiaries to these plans amounted to $100 million, $104 million and $98 million for the years ended December 31, 2011, 2010 and 2009.
Stock Option Plans - In 2005, shareholders approved the amended and restated Loews Corporation 2000 Stock Option Plan (the “Loews Plan”). The aggregate number of shares of Loews common stock for which options or SARs may be granted under the Loews Plan is 12,000,000 shares, and the maximum number of shares of Loews common stock with respect to which options or SARs may be granted to any individual in any calendar year is 1,200,000 shares. The exercise price per share may not be less than the fair market value of the common stock on the date of grant. Generally, options and SARs vest ratably over a four-year period and expire in ten years.
A summary of the stock option and SAR transactions for the Loews Plan follows:
The following table summarizes information about the Company’s stock options and SARs outstanding in connection with the Loews Plan at December 31, 2011:
In 2011, the Company awarded SARs totaling 910,200 shares. In accordance with the Loews Plan, the Company has the ability to settle SARs in shares or cash and has the intention to settle in shares. The SARs balance at December 31, 2011 was 5,112,179 shares. There were 1,813,211 shares and 2,500,784 shares available for grant as of December 31, 2011 and 2010.
The weighted average remaining contractual terms of awards outstanding and exercisable as of December 31, 2011, were 5.6 years and 4.5 years. The aggregate intrinsic values of awards outstanding and exercisable at December 31, 2011 were $37 million and $31 million. The total intrinsic value of awards exercised was $6 million, $9 million and $8 million for the years ended 2011, 2010 and 2009. The total fair value of shares vested was $11 million, $12 million and $10 million for the years ended 2011, 2010 and 2009.
The Company recorded stock-based compensation expense of $10 million, $11 million and $13 million related to the Loews Plan for the years ended December 31, 2011, 2010 and 2009. The related income tax benefits recognized were $4 million, $4 million and $4 million. At December 31, 2011, the compensation cost related to nonvested awards not yet recognized was $12 million, and the weighted average period over which it is expected to be recognized is 2.3 years.
The fair value of granted options and SARs for the Loews Plan were estimated at the grant date using the Black-Scholes pricing model with the following assumptions and results:
Note 16. Reinsurance
CNA cedes insurance to reinsurers to limit its maximum loss, provide greater diversification of risk, minimize exposures on larger risks and to exit certain lines of business. The ceding of insurance does not discharge the primary liability of CNA. A credit exposure exists with respect to property and casualty and life reinsurance ceded to the extent that any reinsurer is unable to meet its obligations or to the extent that the reinsurer disputes the liabilities assumed under reinsurance agreements. Property and casualty reinsurance coverages are tailored to the specific risk characteristics of each product line and CNA’s retained amount varies by type of coverage. Reinsurance contracts are purchased to protect specific lines of business such as property and workers’ compensation. Corporate catastrophe reinsurance is also purchased for property and workers’ compensation exposure. Currently most reinsurance contracts are purchased on an excess of loss basis. CNA also utilizes facultative reinsurance in certain lines. In addition, CNA assumes reinsurance as a member of various reinsurance pools and associations.
The following table summarizes the amounts receivable from reinsurers:
CNA has established an allowance for doubtful accounts on reinsurance receivables. In 2011, CNA reduced its allowance for doubtful accounts by $15 million due to a change in estimate. The additional reduction in the allowance primarily related to write-offs of reinsurance receivable balances.
CNA attempts to mitigate its credit risk related to reinsurance by entering into reinsurance arrangements with reinsurers that have credit ratings above certain levels and by obtaining collateral. On a limited basis, CNA may enter into reinsurance agreements with reinsurers that are not rated, primarily captive reinsurers. The primary methods of obtaining collateral are through reinsurance trusts, letters of credit and funds withheld balances. Such collateral was approximately $3.6 billion and $4.0 billion at December 31, 2011 and 2010.
CNA’s largest recoverables from a single reinsurer at December 31, 2011, including prepaid reinsurance premiums, were approximately $2.5 billion from subsidiaries of Berkshire Hathaway Group, $1.0 billion from subsidiaries of Swiss Re Group and $400 million from subsidiaries of the Hartford Insurance Group. The recoverable from the Berkshire Hathaway Group includes amounts related to third party reinsurance for which a subsidiary of Berkshire Hathaway has assumed the credit risk under the terms of the Loss Portfolio Transfer as discussed in Note 8.
The effects of reinsurance on earned premiums are shown in the following table:
Included in the direct and ceded earned premiums for the years ended December 31, 2011, 2010 and 2009 are $1.5 billion, $1.4 billion and $1.4 billion related to business that is 100% reinsured as a result of a significant captive program.
Life and accident and health premiums are primarily from long duration contracts; property and casualty premiums are primarily from short duration contracts.
Insurance claims and policyholders’ benefits reported on the Consolidated Statements of Income are net of reinsurance recoveries of $1.3 billion, $1.1 billion and $1.3 billion for the years ended December 31, 2011, 2010 and 2009, including $790 million, $735 million and $897 million related to the significant captive program discussed above.
The impact of reinsurance on life insurance inforce is shown in the following table:
As of December 31, 2011 and 2010, CNA has ceded $1.2 billion and $1.3 billion of claim and claim adjustment expense reserves, future policy benefits and policyholders’ funds as a result of business operations sold in prior years. Subject to certain exceptions, the purchasers assumed the third party reinsurance credit risk of the sold business.
Note 17. Quarterly Financial Data (Unaudited)
The sum of the quarterly per share amounts may not equal per share amounts reported for year-to-date periods. This is due to changes in the number of weighted average shares outstanding and the effects of rounding for each period.
(a) Net income for the fourth quarter of 2011 was impacted by CNA unlocking assumptions related to its payout annuity contracts, resulting in a loss recognition of $104 million (after tax and noncontrolling interests), as further discussed in Note 1.
Note 18. Legal Proceedings
In August 2005, CNA and certain insurance subsidiaries were joined as defendants, along with other insurers and brokers, in multidistrict litigation pending in the United States District Court for the District of New Jersey, In re Insurance Brokerage Antitrust Litigation, Civil No. 04-5184 (“GEB”). The plaintiffs’ consolidated class action complaint alleged bid rigging and improprieties in the payment of contingent commissions in connection with the sale of insurance. After various motions and preliminary court rulings providing for further proceedings, all parties executed final settlement documents and the plaintiffs filed a motion for preliminary approval of the settlement in May 2011. In June 2011, the Court entered an order preliminarily approving the settlement. A fairness hearing was held in September 2011 to determine final approval of the settlement. The Court took the matter under advisement and will issue a ruling in due course. As currently structured, the settlement will not have a material impact on the Company’s results of operations or equity. In addition, the Company does not believe it has any material ongoing exposure relating to this matter.
The Company has been named as a defendant in the following two cases alleging substantial damages based on alleged health effects caused by smoking cigarettes or exposure to tobacco smoke, all of which also name a former subsidiary, Lorillard, Inc. or one of its subsidiaries, as a defendant. In Cypret vs. The American Tobacco Company, Inc. et al. (1998, Circuit Court, Jackson County, Missouri), the Company would contest jurisdiction and make use of all available defenses in the event it receives personal service of this action. In Young vs. The American Tobacco Company, Inc. et al. (1997, Civil District Court, Orleans Parish, Louisiana), the Company filed an exception for lack of personal jurisdiction during 2000, which remains pending. A third case, Clalit vs. Philip Morris, Inc., et al. (1998,
Jerusalem District Court of Israel), had been dismissed previously by the District Court. In January 2012 the Supreme Court of Israel denied plaintiff’s request for an additional hearing on a separate appeal, which ended the case. A fourth case, Luciano vs. Alcoa Inc., et al. (2011, Supreme Court, New York County, New York), was dismissed in October 2011.
The Company does not believe it is a proper defendant in any tobacco related cases and as a result, does not believe the outcome will have a material affect on its results of operations or equity. Further, pursuant to the Separation Agreement dated May 7, 2008 between the Company and Lorillard Inc. and its subsidiaries, Lorillard Inc. and its subsidiaries have agreed to indemnify and hold the Company harmless from all costs and expenses based upon or arising out of the operation or conduct of Lorillard’s business, including among other things, smoking and health claims and litigation such as the cases described above.
While the Company intends to defend vigorously all tobacco products liability litigation, it is not possible to predict the outcome of any of this litigation. Litigation is subject to many uncertainties. It is possible that one or more of the pending actions could be decided unfavorably.
The Company and its subsidiaries are also parties to other litigation arising in the ordinary course of business. The outcome of this other litigation will not, in the opinion of management, materially affect the Company’s results of operations or equity.
Note 19. Commitments and Contingencies
Guarantees
In the course of selling business entities and assets to third parties, CNA has agreed to indemnify purchasers for losses arising out of breaches of representation and warranties with respect to the business entities or assets being sold, including, in certain cases, losses arising from undisclosed liabilities or certain named litigation. Such indemnification provisions generally survive for periods ranging from nine months following the applicable closing date to the expiration of the relevant statutes of limitation. As of December 31, 2011, the aggregate amount of quantifiable indemnification agreements in effect for sales of business entities, assets and third party loans was $764 million.
In addition, CNA has agreed to provide indemnification to third party purchasers for certain losses associated with sold business entities or assets that are not limited by a contractual monetary amount. As of December 31, 2011, CNA had outstanding unlimited indemnifications in connection with the sales of certain of its business entities or assets that included tax liabilities arising prior to a purchaser’s ownership of an entity or asset, defects in title at the time of sale, employee claims arising prior to closing and in some cases losses arising from certain litigation and undisclosed liabilities. These indemnification agreements survive until the applicable statutes of limitation expire, or until the agreed upon contract terms expire.
Offshore Rig Purchase Obligations
Diamond Offshore has entered into three separate turnkey contracts with Hyundai Heavy Industries, Co. Ltd., (“Hyundai”) for the construction of three dynamically positioned, ultra-deepwater drillships, with deliveries scheduled for the second and fourth quarters of 2013 and in the second quarter of 2014. The aggregate cost of the three drillships, including commissioning, spares and project management, is expected to be approximately $1.8 billion. The contracted price of each drillship is payable in two installments. The first installments, aggregating $478 million, were paid in 2011 and are included in Property, plant and equipment in the Consolidated Balance Sheets. The final installments of the contracted price are payable to Hyundai upon delivery of each vessel.
In December of 2011, Diamond Offshore entered into an agreement for the construction of a moored semisubmersible rig designed to operate in water depths up to 6,000 feet. The rig will be constructed utilizing the hull of one of Diamond Offshore’s mid-water floaters and is estimated to cost approximately $300 million, including commissioning, spares and project management costs.
Note 20. Business Segments
The Company’s reportable segments are primarily based on its individual operating subsidiaries. Each of the principal operating subsidiaries are headed by a chief executive officer who is responsible for the operation of its business and has the duties and authority commensurate with that position. Investment gains (losses) and the related income taxes, excluding those of CNA, are included in the Corporate and other segment.
CNA’s core property and casualty commercial insurance operations are reported in two business segments: CNA Specialty and CNA Commercial. CNA Specialty provides a broad array of professional, financial and specialty property and casualty products and services, primarily through insurance brokers and managing general underwriters. CNA Commercial includes property and casualty coverages sold to small businesses and middle market entities and organizations primarily through an independent agency distribution system. CNA Commercial also includes commercial insurance and risk management products sold to large corporations primarily through insurance brokers.
CNA’s non-core operations are managed in two segments: Life & Group Non-Core and Other Insurance. Life & Group Non-Core primarily includes the results of the life and group lines of business that are in run-off. Other Insurance primarily includes certain corporate expenses, including interest on corporate debt, and the results of certain property and casualty business primarily in run-off, including CNA Re and A&EP.
Diamond Offshore’s business primarily consists of operating offshore drilling rigs that are chartered on a contract basis for fixed terms by companies engaged in exploration and production of hydrocarbons. Offshore rigs are mobile units that can be relocated based on market demand. Diamond Offshore’s fleet consists of 49 drilling rigs, including three new-build rigs which are under construction and one rig being constructed utilizing the hull of one of Diamond Offshore’s existing mid-water floaters. On December 31, 2011, Diamond Offshore’s drilling rigs were located offshore 13 countries in addition to the United States.
HighMount’s business consists primarily of natural gas exploration and production operations located primarily in the Permian Basin in Texas, with estimated proved reserves totaling approximately 1.1 trillion cubic feet equivalent. In the second quarter of 2010, HighMount sold substantially all of its exploration and production assets located in the Antrim Shale in Michigan and the Black Warrior Basin in Alabama. The Michigan and Alabama properties represented approximately 17%, in aggregate, of HighMount’s total proved reserves as of December 31, 2009.
Boardwalk Pipeline is engaged in the interstate transportation and storage of natural gas. This segment consists of three interstate natural gas pipeline systems originating in the Gulf Coast region, Oklahoma and Arkansas, and extending north and east through the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio, with approximately 14,200 miles of pipeline.
Loews Hotels owns and/or operates 17 hotels, 15 of which are in the United States and two are in Canada.
The Corporate and other segment consists primarily of corporate investment income, including investment gains (losses) from non-insurance subsidiaries, corporate interest expense and other unallocated expenses.
The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 1. In addition, CNA does not maintain a distinct investment portfolio for each of its insurance segments, and accordingly, allocation of assets to each segment is not performed. Therefore, net investment income and investment gains (losses) are allocated based on each segment’s carried insurance reserves, as adjusted.
The following tables set forth the Company’s consolidated revenues and income (loss) by business segment:
(a) Investment gains (losses) included in Revenues, Income (loss) before income tax and noncontrolling interests and Net income (loss) are as follows:
(b) Income taxes and interest expense are as follows:
Note 21. Consolidating Financial Information
The following schedules present the Company’s consolidating balance sheet information at December 31, 2011 and 2010, and consolidating statements of income information for the years ended December 31, 2011, 2010 and 2009. These schedules present the individual subsidiaries of the Company and their contribution to the consolidated financial statements. Amounts presented will not necessarily be the same as those in the individual financial statements of the Company’s subsidiaries due to adjustments for purchase accounting, income taxes and noncontrolling interests. In addition, many of the Company’s subsidiaries use a classified balance sheet which also leads to differences in amounts reported for certain line items.
The Corporate and Other column primarily reflects the parent company’s investment in its subsidiaries, invested cash portfolio and corporate long term debt. The elimination adjustments are for intercompany assets and liabilities, interest and dividends, the parent company’s investment in capital stocks of subsidiaries, and various reclasses of debit or credit balances to the amounts in consolidation. Purchase accounting adjustments have been pushed down to the appropriate subsidiary.
Loews Corporation
Consolidating Balance Sheet Information
Loews Corporation
Consolidating Balance Sheet Information
Loews Corporation
Consolidating Statement of Income Information
Loews Corporation
Consolidating Statement of Income Information
Loews Corporation
Consolidating Statement of Income Information
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
The Company maintains a system of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) which is designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the federal securities laws, including this Report is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Company under the Exchange Act is accumulated and communicated to the Company’s management on a timely basis to allow decisions regarding required disclosure.
The Company’s principal executive officer (“CEO”) and principal financial officer (“CFO”) undertook an evaluation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Report. The CEO and CFO have concluded that the Company’s controls and procedures were effective as of December 31, 2011.
Internal Control Over Financial Reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the implementing rules of the Securities and Exchange Commission, the Company included a report of management’s assessment of the design and effectiveness of its internal controls as part of this Annual Report on Form 10-K for the year ended December 31, 2011. The independent registered public accounting firm of the Company reported on the effectiveness of internal control over financial reporting as of December 31, 2011. Management’s report and the independent registered public accounting firm’s report are included in Item 8 of this Report under the captions entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.
There were no changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the foregoing evaluation that occurred during the quarter ended December 31, 2011, that have materially affected or that are reasonably likely to materially affect the Company’s internal control over financial reporting.
Item 9B. Other Information.
None.
PART III
Except as set forth below and under Executive Officers of the Registrant in Part I of this Report, the information called for by Part III (Items 10, 11, 12, 13 and 14) has been omitted as Registrant intends to include such information in its definitive Proxy Statement to be filed with the Securities and Exchange Commission not later than 120 days after the close of its fiscal year.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) 1. Financial Statements:
The financial statements above appear under Item 8. The following additional financial data should be read in conjunction with those financial statements. Schedules not included with these additional financial data have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes to consolidated financial statements.
Page
Number
2. Financial Statement Schedules:
Loews Corporation and Subsidiaries:
Schedule I-Condensed financial information of Registrant as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009
L-1
Schedule II-Valuation and qualifying accounts for the years ended December 31, 2011, 2010 and 2009
L-3
Schedule V-Supplemental information concerning property and casualty insurance operations as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009
L-4
Description
Exhibit
Number
3. Exhibits:
(3)
Articles of Incorporation and By-Laws
Restated Certificate of Incorporation of the Registrant, dated August 11, 2009, incorporated herein by reference to Exhibit 3.1 to Registrant’s Report on Form 10-Q for the quarter ended September 30, 2009
3.01
By-Laws of the Registrant as amended through October 9, 2007, incorporated herein by reference to Exhibit 3.1 to Registrant’s Report on Form 10-Q filed October 31,
3.02
(4)
Instruments Defining the Rights of Security Holders, Including Indentures
The Registrant hereby agrees to furnish to the Commission upon request copies of instruments with respect to long term debt, pursuant to Item 601(b)(4)(iii) of Regulation S-K
(10)
Material Contracts
Loews Corporation Deferred Compensation Plan amended and restated as of January 1, 2008, incorporated herein by reference to Exhibit 10.01 to Registrant’s Report on Form 10-K for the year ended December 31, 2008
10.01+
Description
Exhibit
Number
Loews Corporation Incentive Compensation Plan for Executive Officers, as amended through October 30, 2009, incorporated herein by reference to Exhibit 10.02 to Registrant’s Report on Form 10-K for the year ended December 31, 2009
10.02+
Loews Corporation 2000 Stock Option Plan, as amended through November 10, 2009, incorporated herein by reference to Exhibit 10.03 to Registrant’s Report on Form 10-K for the year ended December 31, 2009
10.03+
Separation Agreement, dated as of May 7, 2008, by and among Registrant, Lorillard, Inc., Lorillard Tobacco Company, Lorillard Licensing Company LLC, One Park Media Services, Inc. and Plisa, S.A., incorporated herein by reference to Exhibit 10.1 to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2008
10.04
Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and Andrew H. Tisch
10.05*+
Supplemental Retirement Agreement dated January 1, 2002 between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.30 to Registrant’s Report on Form 10-K for the year ended December 31, 2001
10.06+
Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.33 to Registrant’s Report on Form 10-K for the year ended December 31, 2002
10.07+
Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and Andrew H. Tisch, incorporated herein by reference to Exhibit 10.27 to Registrant’s Report on Form 10-K for the year ended December 31, 2003
10.08+
Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and James S. Tisch
10.09*+
Supplemental Retirement Agreement dated January 1, 2002 between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.31 to Registrant’s Report on Form 10-K for the year ended December 31, 2001
10.10+
Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.35 to Registrant’s Report on Form 10-K for the year ended December 31, 2002
10.11+
Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and James S. Tisch, incorporated herein by reference to Exhibit 10.34 to Registrant’s Report on Form 10-K for the year ended December 31, 2003
10.12+
Description
Exhibit
Number
Amended and Restated Employment Agreement dated as of February 14, 2012 between Registrant and Jonathan M. Tisch
10.13*+
Supplemental Retirement Agreement dated January 1, 2002 between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.32 to Registrant’s Report on Form 10-K for the year ended December 31, 2001
10.14+
Amendment No. 1 dated January 1, 2003 to Supplemental Retirement Agreement between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.37 to Registrant’s Report on Form 10-K for the year ended December 31, 2002
10.15+
Amendment No. 2 dated January 1, 2004 to Supplemental Retirement Agreement between Registrant and Jonathan M. Tisch, incorporated herein by reference to Exhibit 10.41 to Registrant’s Report on Form 10-K for the year ended December 31, 2003
10.16+
Supplemental Retirement Agreement dated March 24, 2000 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.01 to Registrant’s Report on Form 10-Q for the quarter ended March 31, 2000
10.17+
First Amendment to Supplemental Retirement Agreement dated June 30, 2001 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10 to Registrant’s Report on Form 10-Q for the quarter ended March 31, 2002
10.18+
Second Amendment to Supplemental Retirement Agreement dated March 25, 2003 between Registrant and Peter W. Keegan and Third Amendment to Supplemental Retirement Agreement dated March 31, 2004 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.44 to Registrant’s Report on Form 10-K for the year ended December 31, 2005
10.19+
Fourth Amendment to Supplemental Retirement Agreement dated December 6, 2005 between Registrant and Peter W. Keegan, incorporated herein by reference to Exhibit 10.1 to Registrant’s Report on Form 8-K filed December 7, 2005
10.20+
Form of Stock Option Certificate for grants to executive officers and other employees and to non-employee directors pursuant to the Loews Corporation 2000 Stock Option Plan, incorporated herein by reference to Exhibit 10.27 to Registrant’s Report on Form 10-K for the year ended December 31, 2009
10.21+
Form of Award Certificate for grants of stock appreciation rights to executive officers and other employees pursuant to the Loews Corporation 2000 Stock Option Plan, incorporated herein by reference to Exhibit 10.28 to Registrant’s Report on Form 10-K for the year ended December 31, 2009
10.22+
Lease agreement dated November 20, 2001 between 61st & Park Ave. Corp. and Preston R. Tisch and Joan Tisch, incorporated herein by reference to Exhibit 10.1 to Registrant’s Report on Form 10-Q filed August 4, 2009
10.23
Description
Exhibit
Number
(21)
Subsidiaries of the Registrant
List of subsidiaries of Registrant
21.01*
(23)
Consent of Experts and Counsel
Consent of Deloitte & Touche LLP
23.01*
Consent of Netherland, Sewell & Associates, Inc.
23.02*
Audit Report of Independent Petroleum Consultants
23.03*
(31)
Rule 13a-14(a)/15d-14(a) Certifications
Certification by the Chief Executive Officer of the Company pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.01*
Certification by the Chief Financial Officer of the Company pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.02*
(32)
Section 1350 Certifications
Certification by the Chief Executive Officer of the Company pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
32.01*
Certification by the Chief Financial Officer of the Company pursuant to 18 U.S.C. Section 1350 (as adopted by Section 906 of the Sarbanes-Oxley Act of 2002)
32.02*
(100)
XBRL - Related Documents
XBRL Instance Document
101.INS **
XBRL Taxonomy Extension Schema
101.SCH **
XBRL Taxonomy Extension Calculation Linkbase
101.CAL **
XBRL Taxonomy Extension Definition Linkbase
101.DEF **
XBRL Taxonomy Label Linkbase
101.LAB **
XBRL Taxonomy Extension Presentation Linkbase
101.PRE **
* Filed herewith.
** The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this Report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections.
+ Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
LOEWS CORPORATION
Dated: February 22, 2012
By
/s/ Peter W. Keegan
(Peter W. Keegan, Senior Vice President and
Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Dated: February 22, 2012
By
/s/ James S. Tisch
(James S. Tisch, President,
Chief Executive Officer and Director)
Dated: February 22, 2012
By
/s/ Peter W. Keegan
(Peter W. Keegan, Senior Vice President and
Chief Financial Officer)
Dated: February 22, 2012
By
/s/ Mark S. Schwartz
(Mark S. Schwartz, Controller)
Dated: February 22, 2012
By
/s/ Lawrence S. Bacow
(Lawrence S. Bacow, Director)
Dated: February 22, 2012
By
/s/ Ann E. Berman
(Ann E. Berman, Director)
Dated: February 22, 2012
By
/s/ Joseph L. Bower
(Joseph L. Bower, Director)
Dated: February 22, 2012
By
/s/ Charles M. Diker
(Charles M. Diker, Director)
Dated: February 22, 2012
By
/s/ Jacob A. Frenkel
(Jacob A. Frenkel, Director)
Dated: February 22, 2012
By
/s/ Paul J. Fribourg
(Paul J. Fribourg, Director)
Dated: February 22, 2012
By
/s/ Walter L. Harris
(Walter L. Harris, Director)
Dated: February 22, 2012
By
/s/ Philip A. Laskawy
(Philip A. Laskawy, Director)
Dated: February 22, 2012
By
/s/ Ken Miller
(Ken Miller, Director)
Dated: February 22, 2012
By
/s/ Gloria R. Scott
(Gloria R. Scott, Director)
Dated: February 22, 2012
By
/s/ Andrew H. Tisch
(Andrew H. Tisch, Director)
Dated: February 22, 2012
By
/s/ Jonathan M. Tisch
(Jonathan M. Tisch, Director)
SCHEDULE I
Condensed Financial Information of Registrant
LOEWS CORPORATION
BALANCE SHEETS
ASSETS
STATEMENTS OF INCOME
L-1
SCHEDULE I
(Continued)
Condensed Financial Information of Registrant
LOEWS CORPORATION
STATEMENTS OF CASH FLOWS
(a) Cash dividends paid to the Company by affiliates amounted to $616, $712 and $947 for the years ended December 31, 2011, 2010 and 2009.
L-2
SCHEDULE II
LOEWS CORPORATION AND SUBSIDIARIES
Valuation and Qualifying Accounts
L-3
SCHEDULE V
LOEWS CORPORATION AND SUBSIDIARIES
Supplemental Information Concerning Property and Casualty Insurance Operations
L-4