July 6, 2011

Securities and Exchange Commission

Division of Corporation Finance

Washington, DC 20549-6010

Attn.:      Jim B. Rosenberg

Senior Assistant Chief Accountant

  Re:        Loews Corporation

Form 10-K for the Fiscal Year Ended December 31, 2010

File No. 001-06541

Via Edgar Filing and Facsimile Transmission

Dear Mr. Rosenberg:

We acknowledge receipt of the letter of comment dated June 10, 2011 from the Commission (the “Comment Letter”) with regard to the above-referenced filing.

Our responses to the Comment Letter are set forth below. For your convenience, the comment presented in the Comment Letter has been repeated herein and is followed by our response. In each instance, we have provided supplemental information to the Staff herein which we believe is responsive to the Staff’s comments. In those instances where we believe additional disclosure should be provided in our future filings, we provide our proposed disclosure at the end of the response. Loews Corporation and its subsidiaries are referred to as “the Company,” “Loews,” “we,” “our” or “us.”

HighMount Exploration & Production LLC, page 11

Reserves, page 13

1. We note your statement, “Due to the five year limitation on proved undeveloped reserves, HighMount reclassified 208 Bcfe of proved undeveloped reserves to the non-proved category. Subsequently, 238 Bcfe of probable reserves were promoted to the proved undeveloped category, as these pertain to locations HighMount expects to drill during the next five years.” Please:

· Explain to us the conditions that you overcame and the technologies you used to allow the probable reserve volumes to be reclassified as proved undeveloped.

Company Response

The Probable locations promoted to Proved were not classified as proved in prior years because they were not scheduled to be drilled within five years. Based on the current drilling plans, these locations now meet the five year rule. The Probable locations converted to PUDs were reclassified based on qualifications of one well offset to existing economic production within a geologically defined hydrocarbon bearing area. Reserves were assigned based on offset reserve assignments of recently drilled (post 2005) wells.

· Provide us with descriptions of the properties to which these two reserve quantities were attributed.

Company Response

The promoted and demoted reserves are predominately in the Canyon reservoir associated with HighMount’s leased acreage around Sonora, TX.

· Address whether the promoted probable reserves were associated with the same properties to which the de-booked 208 Bcfe were attributed.

Company Response

The promoted booked reserves are separate and distinct well locations from those demoted.

· Tell us your total Permian Basin probable reserves figures.

Company Response

In accordance with FASB ASC 932-235-50-2, Registrant has disclosed its proved oil and gas reserve quantities and elected not to disclose its non-proved reserves.

2. We note that you:

· Drilled 212 net Permian Basin development wells in 2010, but converted only 8 Bcfe to proved developed status;

· Added 42 Bcfe in proved reserves by drilling; and

· Expended, in 2010 and 2009 respectively, only 4% of the estimated development costs in your 2009 and 2008 standardized measure towards PUD development. This implies about 20 years to complete development of your booked PUD reserves.

Please explain to us the reasons that this development drilling (i.e. in proved areas) converted only 8 of 304 Bcfe in PUD reserves. Address the expenditure of four percent of the prior year’s estimated development costs in 2010 and 2009.

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Company Response

The low natural gas price environment in the past few years has slowed HighMount’s drilling pace from prior years. Additionally, HighMount has shifted its development priority to higher condensate and higher NGL yield areas within the Sonora property. The reduced activity and focus on high liquid yield wells has resulted in a lower percentage of PUDs being converted to PDP. Based on current forward strip prices, HighMount anticipates increased drilling in future years to complete development of its booked PUD reserves within the five year limitation.

The graph below illustrates HighMount’s ability to drill at the pace necessary to develop its PUDs within the five year limitation when economic conditions warrant. Production can be increased or decreased significantly in response to changing market conditions.

3. Please tell us whether you have disclosed PUD reserves/locations at year-end 2010 that are scheduled for drilling beyond five years from booking.

Company Response

The PUD reserves booked at year-end 2010 are scheduled to be drilled within the five year window.

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Acreage, page 14

4. We note the disclosure of your undeveloped acreage. Item 1208(b) of Regulation S-K requires the disclosure of material, minimum remaining terms of leases and concessions. Please provide us proposed disclosure to be included in future periodic reports to expand your presentation to comply with Regulation S-K.

Company Response

In future Annual Reports on Form 10-K, Registrant will include additional disclosure. As an example, the 2010 Form 10-K would have included the following:

“As of December 31, 2010, there are 68,777, 45,299 and 42,300 net acres scheduled to expire by December 31, 2011, 2012 and 2013, respectively, if production is not established or HighMount takes no other action to extend the terms.”

For reference our current disclosure

“Acreage:  As of December 31, 2010, HighMount owned interests in 591,063 gross developed acres (446,928 net developed acres) and 529,776 gross undeveloped acres (274,557 net undeveloped acres) primarily in the Permian Basin.”

Notes to Consolidated Financial Statements, page 105

Note 15. Supplemental Natural Gas and Oil Information (Unaudited), page 153

5. FASB ASC Subparagraph 932-235-50-23b requires the inclusion of “Production (lifting) costs” with the disclosure of the Results of Operations. We note the Consolidating Statement of Income Information, page 176, does not appear to identify these production costs. Please direct us to the appropriate location in your filing or provide us proposed disclosure to be included in future periodic reports to expand your presentation to comply with ASC 932.

Company Response

Production (lifting) costs are included in HighMount’s “Other operating expenses” on the Consolidating Statement of Income Information, page 176. Expenses of oil and gas producing activities included in Other operating expenses is as follows:

In millions
	2010	2009	2008
Lease operating expenses	71	86	81
Production and ad valorem taxes	27	33	67
Transportation, gathering and processing expenses	19	25	27
Depreciation, depletion and amortization	71	97	161
Asset retirement obligation accretion	1	1	1

Registrant does not consider Production costs to be material to its consolidated results of operations and proposes not to include this disclosure in its future filings.

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6. We note the statement on page five of Exhibit 23.03, your third party engineering report, “For operated properties, the operating costs do not include any corporate general administrative and overhead costs.” With regard to producing well overhead, FASB ASC, paragraph 932-235-50-26 states, “...some expenses incurred at an entity’s central administrative office may not be general corporate expenses, but rather may be operating expenses of oil and gas producing activities, and therefore shall be reported as such.” Please:

· Justify your allocation of no G&A to production costs even though some supervision is an unavoidable requirement for oil and gas production. We recognize that the level of such supervision varies in the industry;

· Furnish to us the figures for each component of your unit historical production costs for each of the last three years;

· Tell us whether you use these same components for production costs in your standardized measure;

· Tell us if you have reduced your disclosed total production costs by including some or all of the COPAS reimbursements you received as operator. If so, tell us the figures for each of the last three years.

Company Response

HighMount’s reserves are contained within a mature gas field requiring minimal corporate supervision of the activities involved in lifting oil and gas to the surface, and to operate and maintain wells and related equipment and facilities. HighMount’s production costs include supervision cost, on-site technical labor cost, and field employee cost. FASB ASC 932-235-50-26 states in part “The nature of an expense rather than the location of its incurrence shall determine whether it is an operating expense. Only those expenses identified by their nature as operating expense shall be allocated as operating expense in computing the results of operations for oil and gas producing activities.” By their nature HighMount’s corporate overhead costs are primarily administrative expenses which cannot be specifically attributed to activities involved in lifting oil and gas to the surface, and operating and maintaining wells and related equipment and facilities. Additionally, as stated in response to Comment #5, Registrant does not consider Production costs to be material to its consolidated results of operations.

Exhibit A details components of historical production costs and whether these components are used in the standardized measure disclosure.

The disclosed total production costs include HighMount’s share of COPAS overhead. The credit for COPAS reimbursements HighMount receives as operator is not included in production cost.

Reserves, page 154

7. We note your statement, “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.” With reasonable detail, please describe to us the engineering methods you used for the initial and for the most recent reserve estimates here. Include the technical basis for the reserve figures and sources for the decline and/or volumetric parameters you used.

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Company Response

The primary methods for reserves determination for both the initial and most recent estimates are decline curve analysis (on PDPs), analogy to offset wells (on PUDs), and volumetric, prior performance, and analogy (on PDNP reserves). The majority of analysis is performed on monthly production values on a well-by-well basis. For wells where production is limited (i.e. recently completed wells) daily data is analyzed.

The 2010 reserve revisions can be broken down into three components: PDP, PUD and PDNP. The most significant revision is PDP performance honoring historical production data with primary emphasis on recent performance. Recent production shows a slightly steeper decline trend throughout the field than was noted in the past. The recent data was honored in HighMount’s estimate of proved reserves that were reported. The PDP reserve revisions necessitated a downward revision in PUD and PDNP reserves.

8. Please tell us if you have commitments to provide a fixed and determinable quantity of oil or gas in the near future under existing contracts or agreements. If so, please provide us proposed disclosure to be included in future periodic reports to include the information specified by Item 1207 of Regulation S-K.

Company Response

Registrant does not have any significant commitments to provide a fixed and determinable quantity of oil or gas in the near future under existing contracts or agreements.

Note 19. Legal Proceedings, page 167

9. Regarding the Insurance Brokerage Anti-trust Litigation, it is not clear how “not readily determinable” in your disclosure “The extent of losses beyond any amounts that may be accrued are not readily determinable at this time” meets the disclosure required by ASC 450-20-50-4. Please provide us proposed disclosure to be included in future periodic reports that complies with ASC 450-20-50-4. If it is the case that an estimate cannot be made, please tell us your process at each reporting date to make this determination, and the facts and circumstance that currently prevent you from making an estimate.

Company Response

At each periodic reporting date the Company updates its assessment of exposure on all outstanding legal contingencies based on the facts and information known as of that date. Based on that assessment, the Company considers the guidance in FASB ASC 450-20-50-4 to determine whether any change in recorded liability or disclosure is required.

Regarding the Insurance Brokerage Anti-trust litigation, as noted in our historical disclosures, CNA strongly believes it has meritorious defenses. Notwithstanding that view, CNA established a $5 million liability a number of years ago anticipating that a modest payment would ultimately be required to resolve this matter.

As noted in our updated disclosure of this matter on page 32 of our Form 10-Q for the quarter ended March 31, 2011, CNA entered into a memorandum of settlement with the plaintiffs to settle this matter for an amount lower than the recorded reserve. While the settlement is currently still subject to court approval, we do not believe the Company has any material ongoing exposure related to this matter. We will include a statement to that effect in our second quarter disclosure.

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The Company will continue to consider the guidance in FASB ASC 450-25-50-4 with respect to future disclosures related to legal contingencies.

As requested in your letter, the Company acknowledges that:

· the Company is responsible for the adequacy and accuracy of the disclosures in the filing;

· staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the Company’s filing; and

· the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Although we are of course amenable to enhancing our disclosures in the context of the Comment Letter, our response should not be considered an indication that we believe any disclosures in the captioned Form 10-K filing were inadequate or incorrect in any material respect.

If you have any questions or further comments, please feel free to contact me at (212) 521-2950, or via fax at (212) 521-2329.

Very truly yours,

/s/ Peter W. Keegan

Peter W. Keegan

Senior Vice President and

Chief Financial Officer

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Exhibit A

HighMount Exploration & Production LLC

Components of Historical Production Costs

(In thousands)

		2010	2009	2008
(a)	Operating Expenses - Lease	$  70,931	$  86,417	$  80,776
(b)	Operating Expenses - Pipelines	3,443	3,536	4,130
(c)	Severance taxes - Lease	17,112	17,269	49,581
(d)	Ad valorem taxes - Lease	9,390	16,046	17,559
(b)	Ad valorem taxes - Pipelines	353	101	165
(d)	3rd Party transportation & gathering	7,601	12,192	14,234
(d)	Gas processing expenses	11,636	12,282	13,107
	Total	$120,466	$147,843	$179,552

(a) Represents HighMount’s share of cost incurred to operate and maintain wells and related equipment such as: first line supervision and company field labor, contract labor, contractor services, materials and supplies, utilities, fuel, compressor rentals, compressor maintenance, field vehicle cost, water disposal and COPAS overhead charged to wells in accordance with applicable joint operating agreements. This cost component is included in the standardized measure excluding COPAS overhead charges.

(b) Represents costs attributable to owned pipelines. For purposes of the standardized measure HighMount includes costs of transportation provided by its pipeline assets based on rates charged to outside third parties for this service.

(c) This cost component is included in the standardized measure. For purposes of the standardized measure applicable statutory rates are used for gas, NGLs and oil adjusted for marketing cost and other incentives.

(d) This cost component is included in the standardized measure.

Note:      Historical Production Costs above include HighMount’s interests in the Michigan and Alabama assets sold in 2010.

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