CALGARY, ALBERTA--(Marketwire - Mar 22, 2013) - Eagle Energy Trust (the "Trust") (TSX:EGL.UN) is pleased to report its financial and operating results for the three month period and year ended December 31, 2012. In addition, the Trust reports that it has filed its Annual Information Form ("AIF"), which includes the Trust's reserves data and other oil and gas information for the period ended December 31, 2012. The audited consolidated financial statements, management's discussion and analysis and AIF have been filed with the securities regulators and are available on the Trust's website at www.EagleEnergyTrust.com and will be available under the Trust's issuer profile on the SEDAR website at www.sedar.com.
This press release contains statements that are forward looking. Investors should read the Note Regarding Forward Looking Statements at the end of this press release.
Highlights for the three months and year ended December 31, 2012
- 2012 average working interest sales volumes of approximately 2,600 barrels of oil equivalent per day ("boe/d") (91% oil) representing a year-over-year increase of 89%.
- Fourth quarter average working interest sales volumes of approximately 3,000 boe/d, up 48% from the 2011 comparable quarter and 6% from the third quarter.
- 2012 funds flow from operations of $35.3 million ($37.14 per boe or $1.43 per unit) representing a year-over-year increase of 78%.
- Fourth quarter funds flow from operations of $9.9 million ($36.06 per boe or $0.34 per unit), up 38% from the 2011 comparable quarter and 10% from the third quarter.
- Fourth quarter field netbacks of $46.67 per boe (2012 average - $47.31 per boe) with realized oil prices of $92.51 per barrel while WTI averaged $88.30.
- 2012 unitholder distributions held steady at $1.05 per unit ($0.0875 per unit per month).
- Total proved and probable reserves of approximately 15.6 million boe (68% proved, 29% proved producing).
- A 188% increase year-over-year in total proved reserves and a 107% increase year-over-year in proved developed producing reserves.
- An 86% increase in total proved reserves per Eagle unit and a 31% increase in proved plus probable reserves per Eagle unit, from December 31, 2011.
- A 2012 proved and probable recycle ratio of 1.9 times (similar to 2011) and a reserve life index of 14.3 years (up 78% from 2011).
- 28 (23.4 net) oil wells drilled during the year and 27 (22.5 net) oil wells tied in and brought on stream during the year.
Management's Commentary on Achievement of 2012 Guidance
The following analysis compares Eagle's 2012 actual results to its latest published 2012 guidance.
- Overall, Eagle's actual volumes did not vary significantly from guidance and Eagle is well positioned to achieve 2013 production targets.
- Average working interest sales volumes of 2,600 boe/d were 96% of 2,700 boe/d guidance.
- Second half average working interest sales volumes of 2,900 boe/d were 97% of 3,000 boe/d guidance.
- Fourth quarter average working interest sales grew 6% from third quarter levels, as compared to a guided growth percentage of 11%.
- Exit rate production guidance of approximately 3,300 boe/d was achieved by early December. Included in Eagle's forecast exit rate was oil production which was subject to a non-consent penalty to a working interest partner in the Luling area. Contrary to Eagle's expectation and after the year end, the partner paid its full share of sunk capital costs to Eagle in return for reinstatement of its working interest share of production. This resulted in a reduction to Eagle's fourth quarter average oil production of approximately 80 boe/d and caused Eagle's full year, second half and fourth quarter actual volumes to come in slightly below guidance.
- Full year average operating costs were $14.48 per boe, compared to $15.00 per boe operating cost guidance. Quarter-over-quarter, operating costs in the fourth quarter also trended $0.30 per boe lower when compared to the third quarter.
- Full year funds flow from operations of $35.3 million was 95% of $37.0 million guidance, with the shortfall being attributable to the volume variances as discussed above.
- Full year capital expenditures of $43.5 million were at the expected $43.0 million level.
- 2012 ending debt to trailing cash flow ratio of 1.1x approximated guidance of 1.0x.
- Eagle paid a steady distribution of 8.75 cents per unit per month, consistent with its statement to sustain distributions.
- The full year payout ratio of 73% (derived by dividing unitholder distributions into funds flow from operations) approximates the stated guidance level of approximately 70%.
- Approximately 65% of Eagle's unitholders presently elect to receive their monthly distributions in Eagle's Premium Drip™ and distribution reinvestment programs. Financing by distribution reinvestment programs is beneficial to Eagle because it represents a significantly lower cost of capital to Eagle compared to other sources of equity financing available at any given time. Eagle utilizes such financing to fund the portion of its capital program which exceeds available cash flow after paying distributions. Such financing remains accretive as long as the rate of return of the capital program exceeds the cost of such capital to Eagle. As is the case with any capital investment, Eagle weighs the benefits against the returns earned from this method of financing and makes adjustments as deemed prudent.
Eagle's average production for the months of January and February 2013 was 2,888 boe/d, which is consistent with Eagle's previously published guidance. Eagle is on target to add additional production with the start of its 2013 capital program, beginning in April with five planned wells in Midland, followed by six planned wells in Luling beginning in June.
Operating costs continue to decline, as evidenced by the fourth quarter operating costs of $13.47 per boe (including transportation costs).
All of Eagle's production is located in the State of Texas. 88% of Eagle's revenue comes from light oil production. Eagle recently renewed its oil marketing arrangement increasing its overall 2013 realized weighted oil price to an approximate $US 2.67 per barrel premium to WTI (excluding estimated transportation costs of $2.00 per boe). By comparison, over the past few months producers of Canadian light and heavy oil have experienced record discounts from WTI for their wellhead prices, by as much as $15 to $40 per barrel, respectively. Having all of its production in the United States gives Eagle a significant pricing advantage over producers of Canadian domestic oil.
This outlook section is intended to provide unitholders with information about Eagle's expectations as at the date hereof for production and capital expenditures for 2013. 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".
2013 Summary Capital, Production and Operating Cost Guidance
On December 7, 2012, the Board of Directors approved a 2013 capital budget of $US 24.0 million (down 45% year-over-year). The budget demonstrates a planned move from a growth phase on the Luling and Midland assets toward a sustainability phase where the level of capital necessary to maintain production, plus distributions paid to unitholders, will be more closely aligned with funds flow from operations.
Management anticipates that, based on 2013 estimated levels of drilling and operating costs, an annual budget of $US 24.0 million should be sufficient to grow 2013 average working interest production by approximately 10-15% over 2012 average working interest production.
With this 2013 capital budget, Eagle intends to execute a 6 (gross) well drilling program at Luling, a 5 (gross) well drilling program at Midland, plus 3 (gross) recompletions at Midland. In addition, a portion of the capital investment will be deployed to add new zones in Midland, test Salt Flat analogs and pilot enhanced recovery initiatives that should flatten the corporate decline, increase recovery rates, and cost effectively add reserves.
Eagle anticipates average 2013 working interest production in the range of 2,900 to 3,100 boe/d (up 10-15% year-over-year) comprised of 88% oil, 8% natural gas liquids ("NGLs") and 4% gas.
Operating costs (inclusive of transportation) per boe are expected to average in the range of $12.00 to $14.00 per boe (down 10% year-over-year).
2013 funds flow from operations of $41.0 million has been estimated using the following assumptions:
- average working interest production of 3,000 boe/d;
- pricing at $US 90.00 per barrel West Texas Intermediate ("WTI") oil, $US 2.90 per Mcf NYMEX gas and $US 39.60 per barrel NGLs (NGLs price is calculated as 44% of the WTI price);
- a $US 2.56 per barrel discount from WTI in Midland (excluding transportation) and a $US 1.89 per barrel discount from WTI in Luling (excluding transportation);
- average operating costs (inclusive of transportation) of $13.00 per boe; and
- foreign exchange at $1.00 CDN/US.
A table showing the sensitivity of Eagle's 2013 funds flow to production and pricing is set out below under the heading "2013 Sensitivities".
2013 Capital Budget
The Board of Directors approved a 2013 capital budget of $US 24.0 million, consisting of the following:
- in the Luling Area:
- 6 (4.8 net) horizontal oil wells
- 2 (1.6 net) salt water disposal well workovers
- Addition to an existing battery
- Land, seismic, workovers
- in the Midland Area:
- 5 (4.6 net) vertical oil wells
- 1 (0.9 net) water source well
- 3 recompletions
The capital budget excludes corporate and property acquisitions, which are evaluated separately on their own merits.
Calculations and commentary regarding the sustainability of Eagle's distributions
The following table sets out Eagle's 2013 guidance with respect to its projected payout ratios, debt to trailing cashflow and percentage drawn on its credit facility.
|Payout Ratios (as a percentage of cash flow)|
|Basic Payout Ratio (i.e., Distribution at $1.05/unit)||77||%||(1||)|
|Plus: Capital Expenditures||59||%||(2||)|
|Equals: Corporate Payout Ratio||136||%||(3||)|
|Adjusted Payout Ratio (i.e., Distribution - DRIP proceeds + Capital Expenditures)||85||%||(4||)|
|Debt to trailing cashflow||0.78||(5||)|
|% Drawn on existing credit facility||66||%|
(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) A portion of the 2013 capital investment, approximately $1.2 million, will be deployed to add new zones in Midland, test Salt Flat analogs and pilot enhanced recovery initiatives that should flatten the corporate decline, increase recovery rates, and cost effectively add reserves.
(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) Approximately 65% of Eagle's unitholders presently elect to receive their monthly distributions in Eagle's Premium Drip™ and distribution reinvestment programs. Financing by distribution reinvestment programs is beneficial to Eagle because it represents a significantly lower cost of capital to Eagle compared to other sources of equity financing available at any given time. Eagle utilizes such financing to fund the portion of its capital program which exceeds available cash flow after paying distributions. Such financing remains accretive as long as the rate of return of the capital program exceeds the cost of such capital to Eagle. As is the case with any capital investment, Eagle weighs the benefits against the returns earned from this method of financing and makes adjustments as deemed prudent.
(5) Management believes the debt to trailing cash flow ratio is a more important measure of financial sustainability than the percentage drawn on current bank facilities. Eagle targets a debt to trailing cash flow ratio of less than 1.5x.
Underlying Asset Quality Benchmarks
Eagle's underlying asset base has the following inherent attributes:
|Oil and Gas Fundamentals||2013 Guidance||Notes|
|Gas Weighting (@ 6:1)||4%|
|Operating Expense||$12.00 to $14.00||(1)|
|(2)||Directly relates to producer's ability to generate free cash flow. Assuming average operating costs (inclusive of transportation) of $13.00 per boe.|
|(3)||Hedging supports sustainability in a volatile commodity price environment (target 50%). 2013 hedges currently in place lock in an average of 1,600 barrels per day using both fixed price contracts and costless collars at WTI prices ranging from $US 87.00 to $US 108.25 per barrel.|
The following tables show the sensitivity of Eagle's funds flow, corporate payout ratio and basic payout ratio to changes in commodity price and production.
Sensitivity of Funds Flow ($ millions) to Commodity Price and Production
|2013 Average WTI|
|$US 80.00||$US 90.00||$US 100.00|
|2013 Average Working Interest Production (boe/d)||2,800||35.3||37.6||41.1|
Sensitivity of Corporate Payout Ratio to Commodity Price and Production
|2013 Average WTI|
|$US 80.00||$US 90.00||$US 100.00|
|2013 Average Working Interest Production (boe/d)||2,800||157%||147%||135%|
Sensitivity of Basic Payout Ratio to Commodity Price and Production
|2013 Average WTI|
|$US 80.00||$US 90.00||$US 100.00|
|2013 Average Working Interest Production (boe/d)||2,800||90%||84%||77%|
|(1)||Annual distributions are held at current levels of $1.05 per unit per year.|
|(2)||No new equity issued, other than distribution reinvestment program.|
|(3)||Field operating costs, including transportation of $13.00 per barrel.|
Selected annual information
The following table shows selected information for the Trust's fiscal year ended December 31, 2012 and December 31, 2011.
|Year ended December 31||2012||2011|
|($000's except per unit amounts and production)|
|Sales volumes - boe/d||2,596||1,376|
|Revenue, net of royalties||58,724||31,771|
|Funds flow from operations||35,298||19,853|
|per unit - basic||1.43||1.11|
|per unit - diluted||1.33||-|
|per unit - basic||0.25||(0.07||)|
|per unit - diluted||0.24||-|
|Total non-current liabilities||42,111||502|
|Cash distributions declared||26,816||19,287|
|per issued unit||1.05||1.05|
|Units outstanding for accounting purposes||29,269(2||)||18,544(1||)|
|(1)||Units outstanding for accounting purposes exclude 387,500 units issued due to the performance conditions that have to be met to enable such units to be released from escrow.|
|(2)||Units outstanding for accounting purposes exclude 105,417 units issued due to the performance conditions that have to be met to enable such units to be released from escrow.|
Summary of quarterly results
|($000's except for boe/d and per unit amounts)|
|Sales volumes - boe/d||2,986||2,825||2,400||2,169||2,023||995||1,214||1,269|
|Revenue, net of royalties||16,519
|Funds flow from operations||9,905||9,039||7,233||9,118||7,199||2,432||5,029||5,192|
|per unit - basic||0.34||0.32||0.31||0.50||0.39||0.14||0.28||0.29|
|per unit - diluted||0.32||-||-||-||-||-||-||-|
|per unit - basic & diluted||(0.02||)||(0.04||)||0.37||(0.05||)||(0.08||)||0.02||0.10||(0.11||)|
|Cash distributions declared||7,653
|per issued unit||0.2625||0.2625||0.2625||0.2625||0.2625||0.2625||0.2625||0.2625|
|Total non-current liabilities||42,111||35,136||27,192||489||503||2,671||4,496||2,893|
|Units outstanding for accounting purposes||29,269(1||)||28,654(1||)||27,895(1||)||18,847(1||)||18,544(1||)||18,174(1||)||17,894(1||)||17,624(1||)|
(1) Units outstanding for accounting purposes exclude those units issued due to the performance conditions that have to be met to enable such units to be released from escrow.
With the exception of the third quarter of 2011, which had approximately 328 barrels per day of oil temporarily shut in due to delays in obtaining Texas Commission on Environmental Quality permits, production has grown commensurate with well tie-ins and acquisitions. A total of 27 (22.5 net) wells were tied in and brought on stream during 2012, with 9 (7.7 net) wells brought on stream during the fourth quarter.
Funds flow from operations increased in the fourth quarter of 2012, when compared to the prior quarters due to higher sales volumes. Second quarter 2012 funds flow from operations also included a one-time transaction cost of approximately $1.5 million associated with the acquisition of the Midland area properties. Generally, in times of steady or increasing prices, funds flow from operations grows as sales volumes increase, and on a per-boe basis, will decline when volumes decline, as they did in the third quarter of 2011. This is because certain expenses tend to be more fixed in nature, such as general and administrative expenses, and do not decrease as sales volumes decrease.
Income (loss) on a quarterly basis often does not move directionally or by the same amount as movements in funds flow from operations. This is primarily due to items of a non-cash nature that factor into the calculation of income (loss), and are required to be fair valued at each quarter end. By way of example, fourth quarter 2012 funds flow from operations increased 10% from the third quarter while fourth quarter income increased by a much larger percentage. This occurred for two reasons. First, a weakened commodity price environment raised the fair market valuation of Eagle's forward commodity contracts. Second, a lower unit price caused a decrease in the expense recorded in the income statement upon performing a fair market valuation of future unit based payments.
A total of 28 (23.4 net) oil wells and 2 (1.6 net) salt water disposal wells were drilled during 2012. Nineteen (15.2 net) oil wells were drilled in the Luling area and 9 (8.23 net) oil wells were drilled in the Midland area. During the fourth quarter, 4 (3.2 net) oil wells were drilled in the Luling area and 5 (4.6 net) oil wells were drilled in the Midland area.
Capital spending during the quarter and year-ended December 31, 2012 and December 31, 2011 was as follows:
|Exploration and evaluation(1)||120||303||-||119|
|Luling area acquisition adjustment||-||-||10||(154||)|
|Midland area acquisition||-||115,902||-||-|
|Intangible drilling and completions||9,628||30,032||2,085||19,938|
|Well equipment and facilities||1,030||12,848||879||7,312|
|$ 11,037||$ 159,359||$ 2,991||$ 27,349|
(1) Exploration and evaluation expenditures relate to amounts spent on land to which no proven reserves are yet assigned.
On May 18, 2012, Eagle acquired 92.5% of the seller's 99% interest in certain Midland area properties and related assets, located near Midland, Texas for total cash consideration of $115.9 million, which includes closing adjustments of approximately $1.4 million. The acquisition had an effective date of April 1, 2012 and a closing date of May 18, 2012. Included in administrative expenses for the year ended December 31, 2012 is approximately $1.5 million of one-time transaction costs associated with this acquisition.
The acquisition agreement provides Eagle with the right and obligation to purchase all of the seller's remaining undivided 7.5% interest in the properties by no later than April 30, 2013 on similar terms and conditions as the acquisition.
A total of 28 (23.4 net) oil wells and 2 (1.6 net) salt water disposal wells were drilled in 2012. In addition, 27 (22.5 net) oil wells were tied in and brought on stream during the year. As previously announced, the early part of Eagle's 2012 drilling program in the Luling area did not meet expectations due to technical issues during well completions. However, once these issues were addressed, wells drilled in the latter part of 2012 performed at forecast levels.
During the fourth quarter, 9 (8.2 net) oil wells were drilled and 9 (7.7 net) oil wells were tied in.
Year end reserves information
On March 1, 2013, the Trust announced the results of the December 31, 2012 independent reserves evaluation that was conducted by GLJ Petroleum Consultants Ltd. ("GLJ") for Eagle's reserves in the Luling area and by Netherland, Sewell & Associates, Inc. for Eagle's reserves in the Midland area. The reserves evaluations are effective December 31, 2012 and were prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
2012 Year end reserves report - highlights
- A 188% increase year-over-year in total proved reserves.
- A 107% increase year-over-year in proved developed producing reserves.
- A $US 46.4 million increase year-over-year in PV10 value of proved developed producing reserves.
- An 86% increase in total proved reserves per Eagle unit (31% increase in proved plus probable reserves per Eagle unit) from December 31, 2011.
- Total proved plus probable reserves of approximately 15.6 million boe (68% proved, 29% proved producing).
- Total proved plus probable reserves additions of 8.9 million boes during 2012 (including the Midland acquisition, and a reduction of 1.1 million boes for probable reserves in the Luling area).
- Reserve life index of 14.3 years (up 78%) based on forecast 2013 average production.
- 83% of the proved producing reserves are light oil, 10% are natural gas and 7% are NGLs.
The following tables summarize the independent reserves estimates and values as at December 31, 2012 of Eagle's reserves:
Summary of Reserves
|Reserves Category||Oil||Natural Gas Liquids||Natural Gas||Total|
|Total Proved Plus Probable||12,593||1,744||7,783||15,635|
(1) Company gross reserves are Eagle's total working interest share before the deduction of any royalties and without including any of Eagle's royalty interests. Eagle holds non-material overriding royalty interests in certain of its assets in the Midland area.
Summary of Net Present Value of Future Net Revenue of Reserves
|Reserves Category||Net Present Value of Future Net Revenue
Before Income Taxes Discounted at (%/year)(1)
|($US 000's||)||($US 000's||)||($US 000's||)||($US 000's||)||($US 000's||)|
|Total Proved Plus Probable||585,041||368,790||264,261||203,909||164,952|
|(1)||Estimates of after-tax future net revenue are not presented because neither Eagle nor the Trust will be subject to taxes in Canada. It should not be assumed that the present values of estimated future net revenue shown above are representative of the fair market value of the reserves. There is no assurance that such price and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of crude oil reserves provided in this report are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may be greater than or less than the estimates provided in this report.|
|(2)||Present values of estimated future net revenue shown above are based on GLJ's escalated price forecast as of January 1, 2013, which assumes a base 2013 oil price of $US 90.00 per barrel of oil (NYMEX WTI at Cushing) and a base 2013 natural gas price of $US 3.75 per million British thermal units of natural gas (NYMEX at Henry Hub).|
Capital program efficiency
For a Trust, proved reserves, particularly proved developed producing reserves, are critical to the sustainability of cash flow and distribution payments. Eagle had a year-over-year increase in total proved reserves of 188%, in proved developed producing reserves of 107% and in the PV 10 value of proved developed producing reserves of $US 46.4 million, all inclusive of the Midland acquisition. In addition, Eagle realized an 86% increase in total proved reserves per Eagle unit and a 31% increase in proved plus probable reserves per Eagle unit from December 31, 2011.
Eagle's business model is to acquire predominantly low risk properties with development and exploitation potential and grow production by converting those non-producing assets to producing assets. Eagle expects to fully book proved plus probable reserves at the time of acquisition and then, over time develop those reserves. Under this business model, it is expected that there would be a moderate to no increase in proved plus probable reserves bookings unless Eagle makes additional acquisitions. As Eagle harvests its assets, there is expected to be regular movement from the probable reserves category into proved reserves.
For 2012, with the increase in Eagle's proved reserves, this evolution is occurring in both the Midland and Luling areas. As previously announced, the early part of Eagle's 2012 drilling program in the Luling area did not meet expectations due to technical issues during well completions. However, once these issues were addressed, wells drilled in the latter part of 2012 performed at forecast levels. Internal technical work by Eagle staff confirms the ultimate potential of the Luling pool. Eagle expects that success in the 2013 drilling program in Luling will meet expectations and replace 2012 reserve adjustments.
The Midland drilling program delivered results as expected in 2012 and reserves in the Midland area remained consistent with prior bookings.
During 2012, Eagle's capital expenditures, including acquisition capital, resulted in capital efficiency statistics as shown in the following table.
|Proved||Proved plus Probable||Proved||Proved plus Probable|
|Exploration and Development expenditures ($000) (1)||43,183||43,183||27,215||27,215|
|Acquisitions ($000) (2)||115,902||115,902||-||-|
|Change in future development capital ($000)|
|Exploration and Development||(16,968||)||(32,617||)||(18||)||741|
|Reserves Additions (Mboes)|
|Exploration and Development||(230||)||(1,319||)||1,137||1,101|
|Acquisition Costs ($/boe) (1)|
|Including change in FDC (3)||26.04||20.63||-||-|
|Excluding change in FDC||14.30||11.33||-||-|
|Finding, Development & Acquisitions Costs ($/boe) (1)(4)|
|Including change in FDC (3)||30.13||24.88||23.93||25.35|
|Excluding change in FDC||20.20||17.86||23.94||24.68|
|Recycle Ratio (5)||1.6x||1.9x||2.1x||2.0x|
|Reserves Replacement (6)||832||%||942||%||226||%||220||%|
|Reserve Life Index (yrs) (7)||9.7||14.3||3.9||8.1|
|(1)||The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.|
|(2)||Acquisition costs related to the 2012 asset acquisition in the Midland area.|
|(3)||Calculation includes changes in future development costs ("FDC").|
|(4)||Eagle calculates finding, development and acquisition ("FD&A") costs which incorporate both the costs and associated reserve additions related to acquisitions during the year. Since acquisitions have a significant impact on Eagle's annual reserve replacement costs, Eagle believes that FD&A costs provide a more meaningful portrayal of Eagle's cost structure.|
|(5)||The recycle ratio is calculated using Eagle's 2012 field netback of $47.31 per boe (2011 - $47.42 per boe) and dividing that number into the FD&A costs per boe.|
|(6)||The reserves replacement ratios are calculated by dividing average working interest production for the year into total reserve additions.|
|(7)||The 2012 reserve life index calculation is based on Eagle's 2013 average working interest production guidance of 3,000 boe/d and the 2011 reserve life index calculation was based on 2,600 boe/d.|
Non-IFRS financial measures
Statements throughout this press release make reference to the terms "funds flow from operations" and "field netback", which are non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers. Investors should be cautioned that these measures should not be construed as an alternative to net income calculated in accordance with IFRS. Management believes that "funds flow from operations" and "field netback" provide useful information to investors and management since these terms 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.
Note regarding 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.
Forward‐looking statements include those pertaining to Eagle's 2013 capital budget amount and specific uses, average working interest production for 2013, drilling inventory and drilling program for 2013 and beyond, 2013 operating costs, commodity prices, funds flow from operations, cash available from the distribution reinvestment and Premium Drip™ programs, payout ratios, sensitivities of the payout ratios to price and production, sustainability of production, and amount of and sustainability of distributions on the Trust's units. In determining its drilling program, timing for bringing wells onto production, the production rates from the wells and operating costs, management has made assumptions relating to, among other things, anticipated future production from wells in the Salt Flat field and Midland area, regulatory approvals, future commodity prices and US/Canadian dollar exchange rates, the regulatory framework governing taxes and environmental matters in the U.S. and Texas, the ability to market future production from the Salt Flat field and Midland area, future capital expenditures and the geological and engineering reserves estimates in respect of Eagle's properties in the Salt Flat Field and Midland area. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
The success of Eagle's drilling program is a key assumption in the production estimates for 2013. The primary risk factors which could lead to Eagle not meeting its production targets are: (i) production additions from drilling activity are less than expected; (ii) a lack of access to drilling rigs and related equipment on a timely basis and at reasonable prices due to high industry demand or poor weather; and (iii) unexpected operational delays and challenges. Increases in capital costs from forecast amounts can result from the foregoing reasons as well as general cost inflation in the industry. Additionally, Eagle may choose to decrease capital expenditures from those anticipated in its budget projections, therefore affecting production estimates for 2013. There are many risk factors inherent in the oil and gas industry in general that could result in production levels being less than anticipated from petroleum reserves, including such risk factors as greater than anticipated declines in existing production due to poor reservoir performance, the unanticipated encroachment of water or other fluids into the producing formation, mechanical failures or human error or inability to access production facilities, among other factors.
These assumptions necessarily involve known and unknown risks and uncertainties inherent in the oil and gas industry such as geological, environmental, technical, drilling and processing problems, the volatility of oil and gas prices, commodity supply and demand, fluctuations in currency and interest rates, obtaining regulatory approvals, competition for services and supplies as well as other business risks that are set out in the Trust's 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. Eagle's production rates, operating costs and 2013 capital budget, and the Trust's distributions, are subject to change in light of ongoing results, prevailing economic circumstances, obtaining regulatory approvals, commodity prices and industry conditions and regulations. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those set out in this press release. 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 operations of Eagle, 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.
Oil and Natural Gas Measures
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 the Trust
Eagle Energy Trust is an energy trust created to provide investors with a publicly-traded, oil and natural gas focused, distribution producing investment, with favourable tax treatment relative to taxable Canadian corporations.
Eagle's units are traded on the Toronto Stock Exchange under the symbol EGL.UN.
- Investment & Company Information