EX-99.1

EX-99.1 3 d530659dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

EXCO RESOURCES, INC. CERTAIN CONVENTIONAL

OIL AND NATURAL GAS PROPERTIES

Statements of Revenues and Direct Operating Expenses

Years ended December 31, 2012, 2011 and 2010

(With Independent Auditors’ Report Thereon)

Independent Auditors’ Report

The Board of Directors and Stockholders

EXCO Resources, Inc.:

Report on the Financial Statements

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) for the years ended December 31, 2012, 2011, and 2010.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the statements of revenues and direct operating expenses in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the statements of revenues and direct operating expenses that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

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 from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the statements of revenues and direct operating expenses. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the statements of revenues and direct operating expenses in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the statements of revenues and direct operating expenses.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit 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 operations of the Properties.

Opinion

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, 2012, 2011, and 2010, in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, TX

April 2, 2013

EXCO Resources, Inc.

Certain Conventional Oil and Natural Gas Properties

Statements of Revenues and Direct Operating Expenses

Years ended December 31, 2012, 2011 and 2010


	Year ended December 31,
(amounts in thousands)	2012		2011		2010

Revenues
Oil and natural gas revenues	$	190,112	$	268,861	$	297,954

Direct operating expenses:
Lease operating expenses		59,381		78,197		84,830
Severance and ad valorem taxes		21,910		22,610		26,079
Gathering and treating expenses		19,401		19,288		27,022

Total direct operating expenses		100,692		120,095		137,931

Excess of revenues over direct operating expenses	$	89,420	$	148,766	$	160,023

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

EXCO Resources, Inc.

Certain Conventional Oil and Natural Gas Properties

Notes to Statement of Revenues and Direct Operating Expenses

Years ended December 31, 2012, 2011 and 2010

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 a newly formed partnership entity, EXCO/HGI JV Assets, LLC, or the Partnership, and hereinafter collectively referred to as the Partnership Properties.

The Partnership was formed on February 14, 2013 pursuant to the agreements governing the transaction between EXCO Resources, Inc., or EXCO, and its subsidiaries and HGI Energy Holdings, LLC, a wholly owned subsidiary of Harbinger Group Inc., or HGI. EXCO contributed certain conventional non-shale assets in East Texas and North Louisiana and its shallow Canyon Sand and other assets in the Permian Basin of West Texas in exchange for cash consideration of $573.3 million, after customary preliminary purchase price adjustments to reflect an effective date of July 1, 2012, and a 25.5% economic interest in the partnership. HGI owns the remaining 74.5% economic interest in the Partnership.

Immediately following closing, the Partnership entered into an agreement to purchase all of the shallow Cotton Valley assets from an affiliate of BG Group plc, or BG Group, for $130.9 million, after customary preliminary purchase price adjustments. The assets acquired as a result of this transaction represented incremental working interests in properties previously owned by the Partnership. The transaction closed March 5, 2013 and was funded with borrowings from the Partnership’s credit agreement.

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, or SEC, for businesses acquired. These statements were prepared from the historical accounting records of EXCO, including the properties purchased from BG Group, as EXCO is the operator of the properties.

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.

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 treating 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 Partnership sells oil or natural gas at the wellhead and collects a price, net of the transportation incurred by the purchaser. In this case, the sales at the price received from the purchaser are reported net of the transportation costs. Under the other arrangement, the Partnership sells oil or natural gas at a specific delivery point, pays transportation to a third party and receives proceeds from the purchaser with no transportation deduction. In this case, the transportation costs are recorded as gathering and treating expense. Due to these two distinct selling arrangements, computed realized prices 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 larger organizations 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, contributions of assets and cash by the Partnership equity holders and acquisition of the Cotton Valley assets from an affiliate of BG Group.

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, 2012, 2011 and 2010, EXCO paid TGGT $13.1 million, $12.0 million and $18.8 million, respectively, in gathering and treating fees related to the Partnership Properties and TGGT purchased $15.3 million, $27.9 million and $33.1 million, respectively, of gas produced by the Partnership Properties.

Note 6. Subsequent events

We have evaluated our activity after December 31, 2012 until the date of issuance of our statements of revenue and direct operating expenses on April 2, 2013, and are not aware of any events that have occurred subsequently to December 31, 2012 that would require adjustments to or disclosures in the statements of revenues and direct operating expenses.

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.

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.


	Oil (Mbbls)			Natural Gas (Mmcf)			NGLs (Mbbls) (1)			Mmcfe (2)
January 1, 2010		5,729			648,027			—			682,401
Production		(719	)		(53,629	)		—			(57,943	)
Extensions and discoveries		1,845			28,691			—			39,761
Revisions of previous estimates:
Changes in prices and costs		584			73,260			—			76,764
Changes in performance and other factors		458			57,484			—			60,232
Purchases of proved reserves in place		1			187			—			193
Sales of proved reserves in place		—			—			—			—


December 31, 2010		7,898			754,020			—			801,408
Production		(764	)		(45,146	)		—			(49,730	)
Extensions and discoveries		917			8,534			—			14,036
Revisions of previous estimates:
Changes in prices and costs		(1,011	)		(167,523	)		—			(173,589	)
Changes in performance and other factors		(328	)		(54,437	)		—			(56,405	)
Purchases of proved reserves in place		—			5,385			—			5,385
Sales of proved reserves in place		—			—			—			—


December 31, 2011		6,712			500,833			—			541,105
Production		(769	)		(38,343	)		(393	)		(45,315	)
Extensions and discoveries		371			12,261			424			17,031
Revisions of previous estimates:
Changes in prices and costs		(256	)		(52,356	)		—			(53,892	)
Changes in performance and other factors		(160	)		(32,754	)		6,589			5,820
Purchases of proved reserves in place		—			—			—			—
Sales of proved reserves in place		—			—			—			—


December 31, 2012		5,898			389,641			6,620			464,749


December 31, 2010:
Proved developed reserves		5,063			592,806			—			623,184
Proved undeveloped reserves		2,835			161,214			—			178,224

Total proved reserves		7,898			754,020			—			801,408


December 31, 2011:
Proved developed reserves		4,922			482,240			—			511,772
Proved undeveloped reserves		1,790			18,593			—			29,333

Total proved reserves		6,712			500,833			—			541,105


December 31, 2012:
Proved developed reserves		4,698			381,277			4,765			438,055
Proved undeveloped reserves		1,200			8,364			1,855			26,694

Total proved reserves		5,898			389,641			6,620			464,749

(1)	Beginning in 2012, we began reporting our natural gas liquids, or NGLs, separately. In 2011 and 2010, the NGLs were reported as a component of natural gas.

(2)	Mcfe - one thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs 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 and natural gas reserves. The following summary is based on a valuation of proved reserves using discounted cash flows based on metrics as prescribed by the SEC, including

prices, 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 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. Income taxes have been excluded from these calculations as the properties were not directly subject to income taxes.

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


(amounts in thousands)

Year ended December 31, 2010
Estimated future cash inflows	$	4,031,085
Future development costs		(523,204	)
Future production costs		(1,855,583	)

Future net cash flows		1,652,298
Discount of future net cash flows at 10%		(868,731	)

Standardized measure of discounted future net cash flows	$	783,567


Year ended December 31, 2011
Estimated future cash inflows	$	3,040,020
Future development costs		(268,817	)
Future production costs		(1,468,017	)

Future net cash flows		1,303,186
Discount of future net cash flows at 10%		(592,197	)

Standardized measure of discounted future net cash flows	$	710,989


Year ended December 31, 2012
Estimated future cash inflows	$	1,871,538
Future development costs		(180,220	)
Future production costs		(1,116,832	)

Future net cash flows		574,486
Discount of future net cash flows at 10%		(219,886	)

Standardized measure of discounted future net cash flows	$	354,600

The reference prices at December 31, 2012, 2011 and 2010 used in the above table, were $94.71, $96.19 and $79.43 per Bbl of oil, respectively, and $2.76, $4.12 and $4.38 per Mmbtu of natural gas, respectively. Beginning in 2012, we began reporting our NGLs separately. In 2011 and 2010, the NGLs were reported as a component of natural gas. The reference price at December 31, 2012 used in the above table was $46.57 per Bbl for NGLs. In each case, the

prices were adjusted for historical differentials. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub, West Texas Intermediate crude oil at Cushing, Oklahoma, and the realized prices for NGLs.

Capital expenditures for oil and gas assets included in the Partnership Properties were $43.7 million, $85.5 million and $137.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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, 2012			Year ended December 31, 2011			Year ended December 31, 2010

Standardized measure - beginning of year	$	710,989		$	783,567		$	534,989

Sales and transfers of oil and natural gas produced (net of production costs)		(89,420	)		(148,766	)		(160,023	)
Net change in prices and production costs		(424,776	)		31,219			206,264
Extensions and discoveries, net of future development and production costs		38,757			46,323			60,973
Previously estimated development costs incurred		24,013			18,358			54,083
Changes in estimated future development costs		55,648			131,895			(105,765	)
Revisions of previous quantity estimates		(47,257	)		(207,263	)		151,227
Purchase of reserves in place		—			4,434			156
Accretion of discount		74,076			81,030			56,531
Other		12,570			(29,808	)		(14,868	)

Change for the year		(356,389	)		(72,578	)		248,578

Standardized measure - end of year	$	354,600		$	710,989		$	783,567