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.
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.
Book value per common share increased to $47.49 at December 31, 2011 as compared to $44.51 at December 31, 2010.
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.
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.
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.
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
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.
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.
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
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
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.
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.
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 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
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’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
Presented below are production and sales statistics related to HighMount’s operations for 2011, 2010 and 2009:
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
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.
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.
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.
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 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.
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.
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.
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.
(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.
The significant components of CNA’s pretax net investment income are presented in the following table:
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.
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:
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.
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.
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.
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.
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).
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
The components of OTTI losses recognized in earnings by asset type are as follows:
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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:
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.
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.
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.
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.
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.
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.
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.
The following table displays the impact of the Loss Portfolio Transfer on the 2010 Consolidated Statement of Income:
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
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, 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.
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 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 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.
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:
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 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.
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.
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.
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.
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 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.
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.
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.
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.
(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.
The aggregate amounts of costs capitalized for natural gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:
(a) Development costs incurred for proved undeveloped reserves were $25, $23 and $27 in 2011, 2010 and 2009.
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 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 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 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:
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.
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.
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 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,
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.
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.
Loews Hotels owns and/or operates 17 hotels, 15 of which are in the United States and two are in Canada.
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.