CALGARY, ALBERTA--(Marketwired - Nov. 8, 2013) - Eagle Energy Trust (the "Trust") (TSX:EGL.UN) is pleased to report its financial and operating results for the third quarter of 2013. The Trust's unaudited interim condensed consolidated financial statements for the nine months ended September 30, 2013 and related management's discussion and analysis have been filed with the securities regulators and are available on the Trust's website at www.EagleEnergyTrust.com or on SEDAR at www.sedar.com. In addition, the Trust has posted video commentary from management regarding its current operations and the third quarter results on its website at http://www.eagleenergytrust.com/videos.

In this press release, references to "Eagle" include the Trust and its operating subsidiaries. All amounts are in Canadian dollars unless otherwise noted.

Highlights for the three months ended September 30, 2013

Eagle continues to demonstrate strong operational execution and consistent quarter over quarter results in 2013.

• Achieved top-decile third quarter field netbacks of $56.79 per barrel of oil equivalent ("boe"). The Trust's realized oil prices were at a premium to the benchmark West Texas Intermediate ("WTI") price. Field marketing contracts negotiated by Eagle contributed to top decile per boe field netbacks. With 100% of its production coming from Texas, Eagle has a substantial revenue advantage over peer Canadian producers.
• Posted third quarter average working interest production of 3,052 boe per day ("boe/d") (80% oil, 11% natural gas liquids, 9% natural gas), which is consistent with second quarter production levels, 8% higher than the comparable 2012 quarter and 22% higher than 2012 on a year to date basis. The Trust remains on track to meet its 2013 full year production guidance of 2,900 to 3,100 boe/d, which will result in greater than 15% year over year growth in average production.
• Lowered full year 2013 operating cost guidance to $12.00 per boe (previously $12.00 to $14.00 per boe) in recognition of ongoing success with operational efficiencies.
• Third quarter funds flow from operations of $11.6 million ($0.37 per unit) was 17% higher than the comparable 2012 quarter ($0.32 per unit). Excluding the $0.7 million one-time cash payment relating to accumulated vested restricted unit rights, second quarter funds flow was also surpassed.
• Third quarter distributions remained consistent at $0.26 per unit or $0.0875 per unit per month.
• Executed the final stages of the 2013 capital program by drilling, tying in and bringing on stream 3 (2.8 net) wells in Luling, and drilling 2 (2.0 net) wells and tying in and bringing on-stream 3 (3.0 net) wells in Midland. All wells were successful.

Commenting on the results, Richard Clark, President and Chief Executive Officer of Eagle, said, "We enjoyed another solid quarter at Eagle. We completed our 2013 drilling program and our new wells have performed as expected this year. Our 'excel at the basics' initiative continues to benefit Eagle. We have lowered our operating costs with improved base production management and operating efficiencies across all of our assets. We have lowered the decline rate with better reservoir management, which bodes well for the sustainability of distributions, as lower decline rates require less capital deployment to replace declining production."

"Once again, Eagle's Texas-based production delivered significant pricing premiums compared to oil produced in Canada. This quarter, Eagle's realized oil price was approximately $113.00 Canadian per barrel. Including the gas and natural gas liquids we produce, we realized over $96.00 Canadian per boe. We are being rewarded for producing light oil located in close proximity to US refineries. 94% of Eagle's revenue comes from oil, placing Eagle in the top decile of the netback per boe metric in our peer group. As of the end of October, Edmonton light sweet crude was priced about $US 16.00 per barrel below WTI and Western Canada Select medium gravity crude was priced about $US 34.00 per barrel below WTI. This represents a significant revenue advantage for Eagle over producers of Canadian oil."

Acquisition

On November 4, 2013, the Trust announced its U.S. subsidiary had signed a purchase and sale agreement to acquire producing properties in Hardeman County, Texas for a purchase price of $US 26.3 million, subject to closing adjustments. The seller's current working interest production from the properties is approximately 300 boe per day, consisting of 97% light sweet crude (43° API) from 34 producing wells. The acquisition is expected to close on or about November 25, 2013, with an effective date of October 1, 2013. The acquisition is very attractive to Eagle as it is accretive in virtually all measures. Eagle estimates the average annual decline rate of the Hardeman County properties to be 12%. In addition, upon successful closing of this acquisition, Eagle's lenders have approved a further increase in Eagle's credit facility to $US 90.0 million consisting of a $US 80.0 million revolving facility and a new one year non-revolving credit facility of $US 10.0 million. The Trust intends to use an advance under this new credit facility to fund the acquisition.

Outlook

This outlook section excludes the Hardeman County acquisition.

This outlook section is intended to provide unitholders with information about Eagle's expectations as at the date of this press release for production, operating costs, and capital expenditures for 2013, among other things. Readers are cautioned that the information may not be appropriate for any other purpose. This information constitutes forward-looking information. Readers should note the assumptions, risks and discussion under "Note about forward-looking statements" at the end of this press release.

The Trust continues to deliver on its 2013 production plan and sustain the progress made in lowering operating costs. Eagle's 2013 annualized production continues to be forecast at 2,900 to 3,100 boe/d and operating cost guidance has been updated to the low end of the range at $12.00/boe.

The Trust has updated its 2013 full year capital guidance to $US 29.2 million (previously $US 26.0 million) due to operational issues, primarily: (1) additional investment during drilling activities for extended coring, logging, and core and cutting analyses in order to mature play concepts in Luling and Midland (including Permian horizontal drilling potential); (2) additional funds to re-drill one Midland well due to issues with a drilling contractor that led to Eagle terminating the relationship and switching rigs and contractor; and (3) additional funds to repair well casing and associated recompletions costs for a well acquired by Eagle at Midland. Eagle is presently seeking reimbursement from the casing manufacturer.

Eagle's updated guidance with respect to its capital budget, production, operating costs and funds flow from operations, excluding the Hardeman County acquisition, is as follows:

	Updated 2013 Guidance	Previous 2013 Guidance	Notes
Capital Budget	$US 29.2 mm	$US 26.0 mm	(1)
Working Interest Production	2,900 to 3,100 boe/d	2,900 to 3,100 boe/d
Operating Costs (inclusive of transportation)	$12.00 per boe	$12.00 to $14.00 per boe	(2)
Funds Flow from Operations	$45.0 mm	$45.0 mm	(3)

Notes:

(1) The capital budget amount does not include the cost of acquisitions.

(2) The Trust expects operating costs for the year to be at the low end of previous guidance.

(3) 2013 funds flow from operations of $45.0 million has been estimated using the following assumptions:

a. based on actual results through to September 30, 2013;

b. full year average working interest production of 3,000 boe/d, which is at the mid-range of guidance;

c. October - December benchmark pricing of $US 100.00 per barrel WTI oil, $US 2.90 per Mcf NYMEX gas and $US 44.00 per barrel NGLs (NGLs price is calculated as 44% of the WTI price);

d. October - December field marketing contracts currently in place for both Midland and Luling, as described in the "Revenue" section of the Management's Discussion and Analysis, and a WTI to LLS premium of $US 3.03 per barrel;

e. October - December average operating costs (inclusive of transportation) of $12.60 per boe; and

f. October - December foreign exchange rate at $1.00 CDN/US.

A table showing the sensitivity of Eagle's 2013 funds flow to changes in production and commodity prices is set out below under the heading "2013 Sensitivities".

The following table sets out Eagle's 2013 updated guidance with respect to its projected payout ratios, debt to trailing cashflow, and percentage to be drawn on its credit facility.

		Updated 2013 Guidance		Previous 2013 Guidance		Notes
Payout Ratios (as a percentage of funds flow)
	Basic Payout Ratio (i.e., assuming annualized distribution at $1.05/unit)	72	%	71	%	(1	)
	Plus: Capital Expenditures	67	%	57	%	(2	)
	Equals: Corporate Payout Ratio	139	%	128	%	(3	)
	Adjusted Payout Ratio (i.e., distribution - DRIP proceeds + capital expenditures)	93	%	83	%	(4	)
Financial Strength
	Debt to trailing cashflow	1.03x		0.88x		(5	)
	% Drawn on existing credit facility at end of period	66	%	66	%	(6	)

Notes:

(1) Eagle calculates its basic payout ratio as follows:

Unitholder Distributions	=	Basic Payout Ratio
Funds Flow from Operations

A table showing the sensitivity of Eagle's basic payout ratio to production and pricing is set out below under the heading "2013 Sensitivities".

(2) Capital expenditures generally exclude corporate and property acquisitions because these are evaluated separately on their own merits. The $US 8.6 million acquisition in Midland and the $US 26.3 million in Hardeman County have therefore been excluded from this percentage.

(3) Eagle calculates its corporate payout ratio as follows:

Capital Expenditures + Unitholder Distributions	=	Corporate Payout Ratio
Funds Flow from Operations

A table showing the sensitivity of Eagle's corporate payout ratio to production and pricing is set out below under the heading "2013 Sensitivities".

(4) Assumes 65% unitholder participation in Eagle's Premium Drip™ and distribution reinvestment programs is unchanged throughout 2013. As is the case with any manner of equity funding, Eagle weighs the benefits of this method of financing and will make adjustments as deemed prudent.

(5) Increased due to updated full year capital guidance.

(6) The borrowing base under the credit facility is $US 70.0 million.

2013 Sensitivities

The following tables show the sensitivity of Eagle's funds flow, corporate payout ratio and basic payout ratio to changes in commodity price and production.

Sensitivity of Funds Flow ($ millions) to Commodity Price and Production

		2013 (Oct - Dec) Average WTI
		$US 90.00	$US 100.00	$US 110.00
2013 Average Working Interest Production (boe/d)	2,900	42.2	42.9	43.5
	3,000	44.2	45.0	45.4
	3,100	46.1	46.7	47.3

Sensitivity of Corporate Payout Ratio to Commodity Price and Production

		2013 (Oct - Dec) Average WTI
		$US 90.00		$US 100.00		$US 110.00
2013 Average Working Interest Production (boe/d)	2,900	147	%	145	%	143	%
	3,000	141	%	139	%	137	%
	3,100	135	%	133	%	132	%

Sensitivity of Basic Payout Ratio to Commodity Price and Production

		2013 (Oct - Dec) Average WTI
		$US 90.00		$US 100.00		$US 110.00
2013 Average Working Interest Production (boe/d)	2,900	77	%	75	%	74	%
	3,000	73	%	72	%	71	%
	3,100	70	%	69	%	69	%

Assumptions:

1. Annual distributions are held at current levels of $1.05 per unit per year.
2. No new equity issued other than under the distribution reinvestment program.
3. Field operating costs (including transportation) from October to December 2013 of $12.60 per barrel.

Summary of quarterly results

		Q3/2013		Q2/2013		Q1/2013		Q4/2012		Q3/2012
($000's except for boe/d and per unit amounts)
Sales volumes - boe/d		3,052		3,022		2,928		2,986		2,825
Revenue, net of royalties		19,517		17,162		16,805		16,519		15,181
	per boe	69.51		62.42		63.77		60.13		58.41
Funds flow from operations		11,615		11,977		11,884		9,905		9,039
	per boe	41.37		43.56		45.10		36.06		34.78
	per unit - basic	0.37		0.39		0.40		0.34		0.32
	per unit - diluted	0.37		0.39		0.40		0.32		0.32
Income (loss)		(3,241	)	3,919		4,080		(403	)	(1,095	)
	per unit - basic & diluted	(0.10	)	0.13		0.14		(0.02	)	(0.04	)
Cash distributions declared		8,204		8,026		7,828		7,653		7,512
	per issued unit	0.2625		0.2625		0.2625		0.2625		0.2625
Current assets		9,950		11,443		9,913		14,464		14,209
Current liabilities		20,942		19,874		11,982		17,512		23,723
Total assets		306,021		311,271		283,112		284,802		283,913
Total non-current liabilities		55,069		50,654		39,873		42,111		35,136
Unitholders' equity		230,010		240,743		231,257		225,179		225,055
Units outstanding for accounting purposes		31,469		30,707(1	)	29,960(1	)	29,269(1	)	28,654(1	)
Units issued		31,469		30,813		30,066		29,375		28,783

Note:

(1) Units outstanding for accounting purposes exclude those units issued due to the performance conditions that had to be met to enable such units to be released from escrow.

Sales volumes in the third quarter of 2013 remained relatively consistent with second quarter 2013 levels. In Luling, three wells were drilled and brought on-stream during the third quarter. Of the three wells that were bought on-stream in Luling, two commenced intermittent production in late September. At Midland, two wells were drilled and three wells were brought on-stream during the third quarter. Once the wells are fractured, they often flow up the casing and cleanup for up to 30 days before a pump is installed and peak well production is achieved. Two of the three Midland oil wells had pumps installed in late September and, even though the wells are performing to expectations, production contributions from the wells were negligible for the quarter.

Funds flow from operations decreased 3% in the third quarter of 2013 when compared to the prior quarter. Although the Trust realized higher WTI prices in the third quarter, resulting in higher revenue when compared to the second quarter of 2013, the increase in revenue was offset by: (1) increased operating expenses in the third quarter 2013 due to non-recurring workover costs on the Midland properties, (2) a one-time payment on vested restricted unit rights and (3) cash payments on risk management contracts. Generally, in times of steady or increasing prices, funds flow from operations will grow as sales volumes increase and, on a per-boe basis, will decline when volumes decline. This is because certain expenses tend to be more fixed in nature, such as general and administrative expenses, and do not decrease as sales volumes decrease.

Income (loss) on a quarterly basis often does not move directionally or by the same amount as movements in funds flow from operations. This is primarily due to items of a non-cash nature that factor into the calculation of income (loss), and items that are required to be fair valued at each quarter end. By way of example, third quarter 2013 funds flow from operations decreased 3% from the second quarter, while third quarter 2013 income decreased by 183%. This occurred for two reasons. First, a stronger commodity price environment during the third quarter of 2013 reduced the fair market valuation of Eagle's forward commodity contracts. Second, a higher unit price caused an increase in the expense recorded in the income statement due to the fair market valuation of future unit-based compensation payments.

Total non-current liabilities increased in the third quarter of 2013 compared to the second quarter of 2013 as a result of the substantial completion of the 2013 capital program. During the third quarter of 2013, the Trust incurred $8.8 million on drilling and completions. Of this total, $7.2 million was for drilling five wells and completing and fracturing six wells. Another $1.6 million was for recompleting existing wells to enhance production.

As a result of a semi-annual review, Eagle's lenders increased the borrowing base under the credit facility from $US 61.0 million to $US $70.0 million effective October 17, 2013.

Non-IFRS financial measures

Statements throughout this press release make reference to the terms "field netback" and "funds flow from operations" which are non-International Financial Reporting Standards ("IFRS") financial measures that do not have any standardized meaning prescribed by IFRS and may not be comparable to similar measures presented by other issuers. Management believes that "field netback" and "funds flow from operations" provide useful information to investors and management since such measures reflect the quality of production, the level of profitability, the ability to drive growth through the funding of future capital expenditures and the sustainability of distributions to unitholders. Funds flow from operations is calculated before changes in non-cash working capital and abandonment expenditures. Field netback is calculated by subtracting royalties and operating costs from revenues. Other financial data has been prepared in accordance with IFRS.

Note about forward-looking statements

Certain of the statements made and information contained in this press release are forward-looking statements and forward looking information (collectively referred to as "forward-looking statements") within the meaning of Canadian securities laws. All statements other than statements of historic fact are forward-looking statements. The Trust cautions investors that important factors could cause the Trust's actual results to differ materially from those projected, or set out, in any forward-looking statements included in this press release.

In particular, and without limitation, this press release contains forward looking statements pertaining to the following:

• the Trust's estimates regarding its 2013 capital budget and specific uses;
• the Trust's expectations regarding its average 2013 working interest production and 2013 operating costs;
• the Trust's expectations regarding its 2013 funds flow from operations and sensitivities of funds flow from operations to production rates and commodity prices;
• the Trust's expectations regarding its 2013 basic and corporate payout ratios and 2013 debt to trailing cashflow;
• the Trust's expectations regarding its bank debt to cash flow ratio;
• the Trust's expectations regarding the percentage to be drawn on its credit facility and specific uses including funding the Hardeman County property acquisition;
• the sensitivities of 2013 payout ratios to changes in production rates and commodity prices;
• the Trust's expectations regarding its overall decline rate;
• the anticipated completion of the Hardeman County property acquisition; and
• the Trust's expectation that its expected funds flow from operations and undrawn credit facility will be sufficient to fund its current and expected financial obligations.

With respect to forward-looking statements contained in this press release, assumptions have been made regarding, among other things:

• future oil, natural gas liquid and natural gas prices;
• future currency exchange and interest rates;
• future recoverability of reserves;
• future distribution levels;
• future capital expenditures and the ability of the Trust to obtain financing on acceptable terms for its capital projects and future acquisitions;
• the Trust's 2013 capital budget, which is subject to change in light of ongoing results, prevailing economic circumstances, commodity prices and industry conditions and regulations;
• not including capital required to pursue future acquisitions in the forecasted capital expenditures;
• estimates of anticipated production, which is based on the proposed drilling program with a success rate that, in turn, is based upon historical drilling success and an evaluation of the particular wells to be drilled;
• projected operating costs, which are based on historical information and anticipated increases in the cost of equipment and services;
• the level of unitholder participation in Eagle's Premium Drip ™ and distribution reinvestment programs; and
• the regulatory framework governing taxes in the U.S. and Canada and the Trust's status as a "mutual fund trust" and not a "SIFT trust".

The Trust's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and those in the Trust's Annual Information Form for the year ended December 31, 2012 (AIF) available on SEDAR at www.sedar.com:

• volatility of oil, natural gas liquid, and natural gas prices;
• commodity supply and demand;
• fluctuations in currency and interest rates;
• inherent risks and changes in costs associated in the development of petroleum properties;
• ultimate recoverability of reserves;
• timing, results and costs of drilling and production activities;
• unexpected operational delays and challenges;
• availability of financing and capital; and
• new regulations and legislation that apply to the Trust and the operations of its subsidiaries.

Additional risks and uncertainties affecting the Trust are contained in the AIF under the heading "Risk Factors".

As a result of these risks, actual performance and financial results in 2013 may differ materially from any projections of future performance or results expressed or implied by these forward‐looking statements. The Trust's production rates, operating costs, drilling program, 2013 capital budget, funds flow from operations payout ratios, tax horizon Eagle's Premium Drip ™ and distribution reinvestment programs and distributions, among other things, are subject to change in light of ongoing results, prevailing economic circumstances, obtaining regulatory approvals, actual commodity prices, and industry conditions and regulations. New factors emerge from time to time, and it is not possible for management to predict all of these factors or to assess, in advance, the impact of each such factor on the Trust's business, or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward looking statement.

Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward looking statements will not occur. Although management believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date the forward-looking statements were made, there can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will in fact be realized. Actual results will differ, and the difference may be material and adverse to the Trust and its unitholders. The Trust does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise.

Note regarding barrel of oil equivalency

This press release contains disclosure expressed as "boe" or "boe/d". All oil and natural gas equivalency volumes have been derived using the conversion ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. In addition, given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf: 1 bbl would be misleading as an indication of value.

About Eagle Energy Trust

Eagle is an oil and gas energy trust created to provide investors with a publicly traded, oil and natural gas focused, reliable distribution paying investment, with favourable tax treatment relative to taxable Canadian corporations.

All material information pertaining to Eagle Energy Trust may be found under Eagle's issuer's profile at www.sedar.com or on Eagle's website at www.EagleEnergyTrust.com.