Exhibit 99.2

Independent Auditors’ Report

The Board of Directors and Stockholders

EXCO Resources, Inc.:

We have audited the accompanying statements of revenues and direct operating expenses of EXCO Resources, Inc.’s Certain Conventional Oil and Natural Gas Properties (the Properties or the Company) for the years ended December 31, 2011, 2010, and 2009. These statements of revenues and direct operating expenses are the responsibility of EXCO Resources, Inc.’s management. Our responsibility is to express an opinion on these statements of revenues and direct operating expenses based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements of revenues and direct operating expenses, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement of revenues and direct operating expenses presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements of revenues and direct operating expenses referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The statements of revenues and direct operating expenses are not intended to be a complete presentation of the revenues and expenses for the Properties.

In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of EXCO Resources, Inc.’s Certain Conventional Oil and Natural Gas Properties for the years ended December 31, 2011, 2010, and 2009 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

December 6, 2012

EXCO Resources, Inc.

Certain Conventional Oil and Natural Gas Properties

Statements of Revenues and Direct Operating Expenses

Years ended December 31, 2011, 2010 and 2009 and

Nine months ended September 30, 2012 and 2011 (Unaudited)

	Year ended December 31,						Nine months  ended September 30,		Nine months  ended September 30,
(amounts in thousands)	2011		2010		2009		2012		2011
							(Unaudited)		(Unaudited)
Revenues
Oil and natural gas revenues	$	224,302	$	242,273	$	299,337	$	118,922	$	174,207
Direct operating expenses:
Lease operating expenses		56,465		61,143		74,581		33,700		41,031
Severance and ad valorem taxes		19,733		21,813		26,603		14,324		16,109
Gathering and treating expenses		13,293		17,642		26,951		9,838		10,280
Total direct operating expenses		89,491		100,598		128,135		57,862		67,420
Excess of revenues over direct operating expenses	$	134,811	$	141,675	$	171,202	$	61,060	$	106,787

See accompanying notes to statements of revenues and direct operating expenses.

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EXCO Resources, Inc.

Certain Conventional Oil and Natural Gas Properties

Notes to Statement of Revenues and Direct Operating Expenses

Years ended December 31, 2011, 2010 and 2009

Note 1. Basis of Presentation

The accompanying historical statements of revenues and direct operating expenses present the revenues less direct operating expenses of certain shallow conventional non-shale oil and natural gas properties owned by EXCO Resources, Inc., or EXCO, EXCO Operating Company, Inc., or EOC, and Vernon Gathering, LLC, each of which are wholly owned subsidiaries of EXCO, and hereinafter collectively referred to as the Partnership Properties, to a newly formed partnership entity, EXCO/HGI JV Assets, LLC, or the Partnership.

Terms of the transaction are set forth in a Unit Purchase and Contribution Agreement, or UPCA, dated November 5, 2012 between EXCO and its aforementioned subsidiaries and HGI Energy Holdings, LLC, a wholly owned subsidiary of Harbinger Group Inc., or HGI. In exchange for the contribution of the Partnership Properties, at closing, EXCO will receive cash consideration of $597.5 million, subject to customary purchase price adjustments to reflect an effective date of July 1, 2012, a 25.5% limited partner interest in the Partnership and a 50% interest in the general partner of the Partnership. The remaining 74.5% of the Partnership will be owned by HGI.

The transaction contemplated by the UPCA is subject to customary pre and post-closing adjustments, including expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, customary title and environmental reviews, closing conditions and regulatory approvals, and is expected to close in early 2013.

The historical statements of revenues and direct operating expenses of the Partnership Properties are presented in order to comply with the rules and regulations of the Securities and Exchange Commission for businesses acquired or probable to be acquired. These statements were prepared from the historical accounting records of EXCO.

Since separate historical financial statements in accordance with accounting principles generally accepted in the United States of America, or GAAP, have never been prepared for the Partnership Properties, certain indirect expenses, as further described in Note 4. Excluded Expenses, were not allocated to the Partnership Properties and have been excluded from the accompanying statements. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties on a stand-alone basis. Accordingly, the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X (balance sheet, income statement, cash flow and statement of stockholders’ equity) prepared in accordance GAAP are not presented and these statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, partners’ equity and cash flows of the Partnership Properties and are not necessarily indicative of the results of operations for the Partnership Properties going forward.

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Note 2. Significant Accounting Policies

Use of Estimates

GAAP requires management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.

Revenue Recognition

Oil and natural gas revenues reflect the sales method of accounting. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. There were no significant imbalances with other revenue interest owners attributable to the Partnership Properties during any of the periods presented in these statements.

Direct Operating Expenses

Direct operating expenses are recognized on an accrual basis and consist of direct expenses of operating the Partnership Properties. The direct operating expenses include lease operating expenses, gathering and treating costs and production and other tax expenses.

• Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs, and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and natural gas production activities.

• Gathering and transportation expenses include the costs to gather and transport oil and natural gas. There are two types of agreements in which oil and gas are sold, both of which include a transportation charge. One is a netback arrangement, under which the Proposed Partnership will sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, the sales at the price received from the purchaser will be reported net of the transportation costs. Under the other arrangement, the Proposed Partnership will sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, the transportation costs are recorded as gathering and transportation expense. Due to these two distinct selling arrangements, computed realized prices, before the impact of derivative financial instruments, include revenues which are reported under two separate bases.

• Production and other taxes consist of severance and ad valorem taxes.

Note 3. Contingencies

The activities of the Partnership Properties are subject to potential claims and litigation in the normal course of operations. EXCO management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Partnership Properties.

Note 4. Excluded Expenses

Prior to the formation of the Partnership, the Partnership Properties were part of a larger organization where indirect general and administrative expenses, interest, income taxes, and other indirect expenses were not allocated to the Partnership Properties and have therefore been excluded from the accompanying statements of revenues and direct operating expenses. In addition, such indirect expenses are not indicative of costs which would have been incurred by the Partnership Properties on a stand-alone basis.

Also, depreciation, depletion and amortization and accretion of discounts attributable to asset retirement obligations have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not necessarily be indicative of those expenses which would have been incurred based on the amounts to be allocated to the oil and gas properties in connection with the formation of the Partnership and contributions of assets and cash by the Partnership equity holders.

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Note 5. Related Parties

EXCO has an equity investment in TGGT Holdings, LLC, or TGGT, which provides gathering and treating services to certain Partnership Properties. In addition, TGGT also purchases natural gas from certain Partnership Properties. For the twelve months ended December 31, 2011, 2010 and 2009, EXCO paid to TGGT approximately $6.0 million, $9.4 million and $24.8 million, respectively, in gathering and treating fees related to the Partnership Properties and TGGT purchased approximately $27.9 million, $33.2 million and $1.7 million of gas produced by the Partnership Properties for the twelve months ended December 31, 2011, 2010 and 2009.

Note 6. Subsequent events

We have evaluated our activity after December 31, 2011 until the date of issuance of our statements of revenue and direct operating expenses on December 6, 2012, and are not aware of any events that have occurred subsequently to December 31, 2011 that would require adjustments to or disclosures in the statements.

Note 7. Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Reserves

Independent engineering firms are retained to provide annual year-end estimates of future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves shown below include only those quantities that are expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that might be recovered through existing wells. Proved Undeveloped Reserves include those reserves that might be recovered from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of the reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

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The following table sets forth estimates of the proved oil and natural gas reserves (net of royalty interests) and changes therein, for the Partnership Properties for the periods indicated.

(amounts in thousands)	Oil (Bbls)			Natural Gas (Mcf)			Mcfe (1)
January 1, 2009		7,509			873,564			918,618
Production		(779	)		(64,358	)		(69,032	)
Extensions and discoveries		183			32,288			33,386
Revisions of previous estimates
Changes in performance and costs		(724	)		(102,243	)		(106,587	)
Changes in performance and other factors		(383	)		(54,013	)		(56,311	)
Purchases of proved reserves in place		—			218			218
Sales of proved reserves m place		(1,071	)		(183,879	)		(190,305	)
December 31, 2009		4,735			501,577			529,987
Production		(629	)		(42,118	)		(45,892	)
Extensions and discoveries		1,616			26,024			35,720
Revisions of previous estimates:
Changes in prices and costs		635			68,499			72,309
Changes in performance and other factors		670			72,263			76,283
Purchases of proved reserves in place		—			96			96
Sales of proved reserves in place		—			—			—
December 31, 2010		7,027			626,341			668,503
Production		(690	)		(35,614	)		(39,754	)
Extensions and discoveries		912			7,722			13,194
Revisions of previous estimates:
Changes in prices and costs		(794	)		(133,428	)		(138,192	)
Changes in performance and other factors		(302	)		(50,735	)		(52,547	)
Purchases of proved reserves in place		—			4,672			4,672
Sales of proved reserves in place		—			—			—
December 31, 2011		6,153			418,958			455,876
December 31, 2009:
Proved developed reserves		2,896			419,854			437,230
Proved undeveloped reserves		1,839			81,723			92,757
Total proved reserves		4,735			501,577			529,987
December 31, 2010:
Proved developed reserves		4,330			482,307			508,287
Proved undeveloped reserves		2,697			144,034			160,216
Total proved reserves		7,027			626,341			668,503
December 31,2011:
Proved developed reserves		4,364			400,364			426,548
Proved undeveloped reserves		1,789			18,594			29,328
Total proved reserves		6,153			418,958			455,876

(1) Mcfe – one thousand cubic feet equivalent calculated by converting one Bbl of oil to six Mcf of natural gas.

Standardized Measure of Discounted Future Net Cash Flows

Summarized below is the Standardized Measure related to the Partnership Properties proved oil, natural gas reserves. The following summary is based on a valuation of proved reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate. The additions to proved reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the present value of future net cash flows does not purport to be an

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estimate of the fair market value of the Partnership Properties proved reserves, nor should it be indicative of any trends. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money, and the risks inherent in producing oil and natural gas.

The following table sets forth estimates of the standardized measure of discounted future net cash flows form proved reserves of oil and natural gas for the periods indicated.

(amounts in thousands)
Year ended December 31, 2009
Estimated future cash inflows	$	1,936,212
Future development costs		(286,305	)
Future production costs		(843,671	)
Future net cash flows		806,236
Discount of future net cash flows at 10%		(374,995	)
Standardized measure of discounted future net cash flows	$	431,241
Year ended December 31, 2010
Estimated future cash inflows	$	3,421,997
Future development costs		(449,293	)
Future production costs		(1,537,209	)
Future net cash flows		1,435,495
Discount of future net cash flows at 10%		(764,251	)
Standardized measure of discounted future net cash flows	$	671,244
Year ended December 31, 2011
Estimated future cash inflows	$	2,655,911
Future development costs		(225,688	)
Future production costs		(1,236,551	)
Future net cash flows		1,193,672
Discount of future net cash flows at 10%		(552,664	)
Standardized measure of discounted future net cash flows	$	641,008

Capital expenditures for the Partnership Properties were $60.8 million, $110.0 million and $123.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves attributable to the Partnership Properties for the periods indicated.

(amounts in thousands)	Year ended December 31, 2011			Year ended December 31, 2010			Year ended December 31, 2009
Standardized measure – beginning of year	$	671,244		$	431,241		$	1,324,036
Sales and transfers of oil and natural gas produced (net of production costs)		(134,811	)		(141,675	)		(171,202	)
Net change in prices and productions costs		59,592			189,928			(680,736	)
Extensions and discoveries, net of future development and production costs		45,574			57,396			28,328
Previously estimated development costs incurred		18,358			45,803			74,817
Changes in estimated future development costs		182,803			(88,356	)		211,484
Revisions of previous quantity estimates		(172,538	)		137,640			(254,892	)
Purchase of reserves in place		3,851			78			192
Sales of reserves in place		—			—			(227,479	)
Accretion of discount		69,275			45,417			133,788
Other		(102,340	)		(6,228	)		(7,095	)
Change for the year		(30,236	)		240,003			(892,795	)
Standardized measure – End of Period	$	641,008		$	671,244		$	431,241

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