Titan Energy 8-K/A Financial Statements and Exhibits

Exhibit 99.4

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following tables summarize the net ownership interest in the proved oil and gas reserves and the standardized measure of discounted future net cash flows related to the proved oil and gas reserves for the Properties and are derived from the reserve reports prepared for Titan Operating, LLC (“The Company”) and annual financial statements for the years ended December 31, 2011, 2010 and 2009. For these periods, independent third-party reserve engineers were retained to prepare a report of proved oil and gas reserves related to the Company. The standardized measure presented here excludes income taxes as the Company is a limited liability company and is not liable for federal income taxes. The proved oil and gas reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the Financial Accounting Standards Board and the SEC.

Proved Oil and Gas Reserve Quantities

Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The net proved oil and gas reserves and changes in net proved oil and gas reserves attributable to the Company’s properties, all of which are located in the state of Texas, are summarized below:

2009
	Crude Oil (MBbls)		Natural Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved developed and undeveloped reserves —
January 1, 2009		—		—			—
Extensions and discoveries		—		18,829			—
Revisions of previous estimates		—		—			—
Production		—		(183	)		—
End of year - December 31, 2009		—		18,646			—
Proved developed reserves at beginning of year		—		—			—
Proved developed reserves at end of year		—		4,984			—
Proved undeveloped reserves at beginning of year		—		—			—
Proved undeveloped reserves at end of year		—		13,662			—

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2010
	Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved developed and undeveloped reserves —
January 1, 2010		—			18,646			—
Extensions and discoveries		13			86,972			7,558
Revisions of previous estimates		—			(273	)		405
Production		(2	)		(5,465	)		(203	)
End of year - December 31, 2010		11			99,880			7,760
Proved developed reserves at beginning of year		—			4,984			—
Proved developed reserves at end of year		11			43,638			2,117
Proved undeveloped reserves at beginning of year		—			13,662			—
Proved undeveloped reserves at end of year		—			56,242			5,643
2011
	Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)
Proved developed and undeveloped reserves —
January 1, 2011		11			99,880			7,760
Extensions and discoveries		2			25,724			526
Revisions of previous estimates		8			(11,015	)		(2,231	)
Production		(3	)		(7,194	)		(202	)
End of year - December 31, 2011		18			107,395			5,852
Proved developed reserves at beginning of year		11			43,638			2,117
Proved developed reserves at end of year		4			48,701			1,987
Proved undeveloped reserves at beginning of year		—			56,242			5,643
Proved undeveloped reserves at end of year		14			58,694			3,865

Capitalized Costs Related to Oil and Gas Producing Activities

The components of capitalized costs related to oil and gas producing activities of the Company during the periods indicated were as follows:

	December 31,
	2011			2010			2009
	(in thousands)
Proved Properties	$	344,820		$	14,491		$	22,796
Unevaluated Properties		91,680			238,535			231,157
		436,500			353,026			253,953
Accumulated depreciation, depletion and amortization		(248,768	)		(25,522	)		(15,806	)
Net capitalized costs	$	187,732		$	327,504		$	238,147

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Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Unproved Property Acquisition	$	11,361	$	27,881	$	42,400
Exploration Costs		3,469		7,541		1,301
Development Costs		69,521		64,668		11,657
	$	84,351	$	100,090	$	55,358

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities were as follows:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Revenues	$	30,886		$	23,305		$	725
Lease Operating Expenses		(3,210	)		(1,039	)		(13	)
Taxes		(2,120	)		(1,535	)		(61	)
Accretion of Asset Retirement Obligation		(26	)		(10	)		(2	)
DD&A		(26,500	)		(9,796	)		(425	)
Full Cost Ceiling Write Down		(196,835	)		—			(15,445	)
	$	(197,805	)	$	10,925		$	(15,221	)

Standardized Measure

Pursuant to SEC guidelines, the standardized measure utilizes the unweighted trailing 12-month arithmetic average of the first of month natural gas and crude oil benchmark prices. The average prices used for 2011, 2010 and 2009 under these rules were $96.19 and $79.43, and N/A per barrel, respectively, for crude oil, condensate, and natural gas liquids (WTI - Cushing, Oklahoma), and $4.12, $4.38 and $3.87 per MMbtu, respectively, for natural gas (Henry Hub).

Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows. As mentioned above, the standardized measure presented below does not include the effects of income taxes as the Company is not subject to income tax. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil and gas reserve estimates.

The standardized measure of discounted future net cash flows before income taxes related to the proved oil and gas reserves of the Company’s properties is as follows:

	December 31,
	2011			2010			2009
	(in thousands)
Future cash inflows	$	585,053		$	635,848		$	60,098
Future production costs		(171,389	)		(168,695	)		(20,510	)
Future development costs		(116,579	)		(122,566	)		(14,140	)
Future net cash flows		297,085			344,587			25,447
Less 10% annual discount to reflect timing of cash flows		(201,032	)		(210,637	)		(18,457	)
Standard measure of discounted future net cash flows	$	96,053		$	133,950		$	6,990

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The following table summarizes changes in the standardized measure of discounted future net cash flows:

	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Changes in Standardized Measure:
Standardized measure — beginning of year	$	133,950		$	6,990		$	—
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		(6,548	)		7,562			—
Net change in estimated future development costs		(13,657	)		(4,839	)		—
Net change due to revisions in quantity estimates		(22,266	)		810			—
Accretion of discount		13,395			699			—
Changes in production rates (timing) and other		(2,564	)		10,032			—
Total revisions		(31,640	)		14,264			—
Net change due to extensions and discoveries, net of estimated future development and production costs		7,404			129,869			7,641
Sales of oil and gas produced, net of production costs		(25,555	)		(20,731	)		(651	)
Previously estimated development costs incurred		11,894			3,558	��		—
Net change in standardized measure of discounted future net cash flows		(37,897	)		126,960			6,990
Standardized measure — end of year	$	96,053		$	133,950		$	6,990

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