CALGARY, ALBERTA--(Marketwired - March 19, 2015) - Eagle Energy Trust (TSX:EGL.UN) ("Eagle" or the "Trust") is pleased to report its financial and operating results for the three months and year ended December 31, 2014 and its 2014 reserves information.
"Our key focus in 2014 was to improve the sustainability of our business while maintaining a strong balance sheet. We believe we succeeded and that our efforts have set us apart from our peer group", said Richard Clark, the Trust's President and CEO. "In 2014, we sold our Permian asset when commodity prices were strong in August and then took advantage of the downturn in the market in December to acquire the Dixonville asset - a premier long life Canadian asset. At the same time, we reduced our debt levels by over $50 million."
Mr. Clark continued, "Our ability to transact in a timely manner, to quickly adjust our capital program to adapt to changing commodity prices, and our success at achieving cost savings through active negotiations with our suppliers, has had a significant positive impact on the sustainability of our business. Also, the recent expansion of our credit facility affords us some dry powder for future growth as accretive opportunities become available. Lastly, we replaced more than 100% of the barrels we produced in 2014, despite our capital budget being predominantly limited to sustaining capital."
The Trust's reserves data and other oil and gas information is included in its Annual Information Form ("AIF"). 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.
Conference Call
Mr. Clark, Kelly Tomyn, Chief Financial Officer, and Wayne Wisniewski, Chief Operating Officer, will host a conference call and webcast on Friday, March 20 at 9:00 a.m. MDT (11:00 a.m. EDT) to discuss the results. To participate in the conference call, dial toll free 888-847-2288 or (678-967-4440) approximately 10 minutes prior to the call and enter the code 93147447. To listen to the call on the web, visit http://www.gowebcasting.com/6342 at the time of the call. A question and answer period will follow the call.
Two hours after the live call, a digital recording will be available for replay until midnight on April 3, 2015. To access the recording, call 800-585-8367 and quote this conference ID: 93147447. An audio version will also be available on Eagle's website at www.eagleenergytrust.com.
In this news release, references to "Eagle" include the Trust and its operating subsidiaries. This news release contains statements that are forward-looking. Investors should read the "Note regarding forward-looking statements" near the end of this news release.
Highlights for the year ended December 31, 2014
Management's 2014 objective was to reduce the overall decline rate of Eagle's assets and the capital necessary to maintain production levels. Achieving this objective increased Eagle's free cash flow and improved the sustainability of its business.
Eagle achieved the following results in 2014:
- Sold its Permian asset (Texas) in August 2014 while commodity prices were strong, and redeployed roughly two-thirds of the sale proceeds during the downturn in commodity prices to acquire the Dixonville asset (Alberta) in December 2014 for $100.9 million.
- These transactions resulted in net proceeds of $50 million (used to retire debt), an increase to corporate production of 250 boe/d and an increase to free cash flow of $6.6 million.
- Continued to manage Eagle in a financially prudent manner, with 2014 year end debt to trailing cash flow of 1.1x and $34.7 million ($US 29.3 million) of credit available on the Trust's existing facility.
- Increased proved developed producing reserves volumes by 88% and the net present value discounted at 10% ("PV10") by 29%.
- Despite a substantial decline in year over year benchmark oil prices, achieved a 4% increase in total proved reserve volumes and a 2.4% increase in total proved reserves value (PV10).
- Achieved a total proved reserve replacement ratio of 145% and total proved plus probable reserve replacement ratio of 265%.
- Reported average working interest sales volumes of 2,782 barrels of oil equivalent per day ("boe/d") (85% oil, 8% natural gas liquids ("NGLs"), 7% natural gas). Current working interest production approximates 3,000 boe/d (97% oil).
- 85% of Eagle's 2014 production was oil and Eagle realized an average oil price of $100.99 per barrel, while the WTI benchmark averaged $US 93.00.
- Reported funds flow from operations of $34.0 million ($33.34 per boe or $1.01 per unit), notwithstanding the August 2014 disposition of the Permian assets.
- Maintained 2014 unitholder distributions at $0.0875 per unit per month from November 2010 to November 2014, then took action to protect its balance sheet in light of current and expected decrease in commodity prices by lowering its monthly distribution to $0.03.
Acquisition in December 2014
On December 18, 2014, a newly formed Canadian subsidiary of the Trust closed the acquisition of a 50% non-operated working interest in producing properties near the town of Dixonville, in the Peace River area of Alberta, for $100.9 million. Through the acquisition of this premier, long-life, oil producing water-flood property, Eagle acquired interests in 112 (56 net) producing wells, 82 (41 net) injection wells and associated facilities, gathering systems and pipelines. With less than 10% average annual decline, stable production base and low sustaining capital requirement, the Dixonville asset substantially reduced Eagle's total corporate sustaining capital requirements and dropped its corporate decline rate from approximately 30% to under 20%. The acquired working interest production at the date of the acquisition was approximately 1,250 boe per day for a purchase price metric of approximately $80,000 per flowing boe/d. The effective date of the acquisition was January 1, 2015.
This acquisition was funded with $55 million of the Trust's available cash and the balance from its existing credit facility. Concurrent with the closing of the acquisition, Eagle's credit facility was expanded to $US 70 million. On February 11, 2015, the credit facility was further expanded to $US 95 million. Amounts drawn on the credit facility can be denominated in US or Canadian dollars and provide Eagle with a funding source to grow through accretive opportunities that become available.
2015 Budget and Outlook
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 2015. 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 discussions under "Note about forward-looking statements" at the end of this news release.
There have been no changes to Eagle's 2015 average production forecast of 2,950 to 3,150 boe/d on a $13.7 million capital budget ($US 9.9 million for its operations in the United States and $1.4 million for its operations in Canada), as originally disclosed in its February 12, 2015 news release.
Eagle's 2015 capital and operating budget is designed to minimize the capital spend necessary to sustain production levels, and then add a designated component of growth-focused capital. 2015 is expected to be a year of volatile commodity prices and Eagle's budget has been designed to reflect these circumstances.
The 2015 capital budget of $13.7 million ($US 9.9 million in the US and $1.4 million in Canada), consists of the following:
- Salt Flat, Texas
- 3 (3.0 net) horizontal oil wells
- Seismic processing, pump changes
- Hardeman, Texas and Oklahoma
- 3 (3.0 net) vertical wells
- 1 (1.0 net) salt water disposal well
- Facilities and seismic capital
- Dixonville, Alberta (non-operated)
- Maintenance capital on waterflood
Eagle's 2015 budget in Canada ($1.4 million) will be limited to maintenance capital at Dixonville. For its U.S. operations, Eagle's 2015 budget ($US 9.9 million) continues to focus on asset development in Texas and Oklahoma and delivering Eagle's commitment of sustainability, both at Salt Flat and at Hardeman. Eagle is evaluating seismic data from its 2014 seismic programs at Salt Flat and at Hardeman. The opportunity at Salt Flat is to better understand the faulting system in the field, and to identify reserves that have not been accessed by Eagle's existing wells and infrastructure. Eagle's focus at the Hardeman property is to continue to identify and delineate Chappell formation locations and to carry on from its successful 2014 drilling program in the area.
Eagle's 2015 guidance for its capital budget, production, operating costs and funds flow from operations is as follows:
2015 Guidance |
Notes | |
| Capital Budget | $ 13.7 mm | 1 |
| Working Interest Production | 2,950 to 3,150 boe/d | 2 |
| Operating Costs per month | $1.8 to $2.0 mm | 3 |
| Funds Flow from Operations | $29.5 mm | 4 |
| Debt to Trailing Cash Flow | 1.2x |
| Notes: | |||
| (1) | The 2015 capital budget of $13.7 million consists of $US 9.9 million for Eagle's operations in the United States and $1.4 million for Eagle's operations in Canada.Based on a $US 60.00 WTI oil price, the 2015 capital budget is expected to deliver a distribution of $0.03 per unit per month ($0.36 per unit annualized) and a corporate payout ratio of 88%. | ||
| (2) | 2015 production forecast consists of 97% oil, 1% natural gas liquids ("NGLs") and 2% gas. | ||
| (3) | 2015 forecast operating costs result in field netbacks (excluding hedges) of approximately $26.41 per boe at $US 60.00 WTI. | ||
| (4) | Funds flow from operations in 2015 is approximately $29.5 million based on the following assumptions: | ||
| a. | Average working interest production of 3,050 boe/d (the mid-point of the guidance range); | ||
| b. | Pricing at $US 60.00 per barrel WTI oil, $US 3.00 per Mcf NYMEX gas and $US 21.00 per barrel of NGL (NGL price is calculated as 35% of the WTI price); | ||
| c. | Differential to WTI is a $US 6.15 discount per barrel in Salt Flat, a $US 2.70 discount per barrel in Hardeman and a $CA 15.00 discount per barrel in Dixonville; | ||
| d. | Average operating costs of $1.9 million per month ($US 0.9 million per month for Eagle's operations in the United States and $0.7 million per month for Eagle's operations in Canada) being the mid-point of the guidance range; and | ||
| e. | Foreign exchange rate of $US 1.00 equal to $CA 1.25. | ||
A table showing the sensitivity of Eagle's funds flow to changes in production, exchange rates and commodity pricing is set out below under the heading "2015 Sensitivities".
Calculations regarding Eagle's distributions
Eagle calculates its payout ratios and financial strength as follows:
| Payout Ratios (as a percentage of cash flow) | 2015 Guidance |
Notes |
| Basic Payout Ratio | 42% | 1 |
| Plus: Capital Expenditures | 46% | |
| Equals: Corporate Payout Ratio | 88% | 2 |
| Financial Strength | ||
| Debt to Trailing Cash Flow | 1.2x |
| Notes: |
| (1) Eagle calculates its Basic Payout Ratio as follows: |
| Unitholder Distributions | = | Basic Payout Ratio |
| Funds Flow from Operations |
| (2) Eagle calculates the 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 changes in production, exchange rates and commodity pricing is set out below under the heading "2015 Sensitivities".
| Underlying asset quality benchmarks | ||
| Oil and Gas Fundamentals | 2015 Guidance |
Notes |
| Oil Weighting | 97 % | |
| Gas Weighting (@ 6 Mcf:1 bbl) | 2 % | |
| NGL Weighting | 1 % | |
| Operating costs per month | $1.8 to $2.0 million | 1 |
| Field Netbacks per boe | $26.41 | 2 |
| % Hedged | 36 % | 3 |
| Notes: | |||
| (1) | Operating costs are stated on a per month basis rather than per boe due to the mostly fixed nature of the costs. | ||
| (2) | Assumes average operating costs of $1.9 million per month (the mid-point of the guidance range) at a $US 60.00 WTI price and excludes hedges. | ||
| (3) | Hedging supports sustainability in a volatile commodity price environment. For the first half of 2015, 1,600 barrels of oil per day is hedged at an average price of $US 90.00.For the second half of 2015, 590 barrels of oil per day are hedged at an average price of $US 87.00. | ||
2015 Sensitivities
The following tables show the sensitivity of Eagle's funds flow, corporate payout ratio and net debt to cash flow to changes in commodity price, exchange rates and production:
| Sensitivity to Commodity Price | |||
| 2015 Average WTI | |||
| $US 50 (FX 1.30)(5) |
$US 60 (FX 1.25)(5) |
$US 70 (FX 1.20)(5) |
|
| Cash Flow | $28.2 | $29.5 | $31.3 |
| Corporate Payout Ratio | 95% | 88% | 82% |
| Leverage | 1.3x | 1.2x | 1.0x |
| Sensitivity to Production | |||
| 2015 Average Production (boe/d) | |||
| 2,950 | 3,050 | 3,150 | |
| Cash Flow | $28.8 | $29.5 | $30.8 |
| Corporate Payout Ratio | 91% | 88% | 85% |
| Leverage | 1.2x | 1.2x | 1.1x |
| Assumptions: | ||
| (1) | Annual distributions are $0.36 per unit. | |
| (2) | No new equity issued. | |
| (3) | Operating costs of $1.9 million per month (the mid-point of the guidance range). | |
| (4) | Differential to WTI held constant. | |
| (5) | The foreign exchange rate is assumed to be as follows: | |
| • | At $US 50.00 WTI - $US 1.00 equal to $CA 1.30. | |
| • | At $US 60.00 WTI - $US 1.00 equal to $CA 1.25. | |
| • | At $US 70.00 WTI - $US 1.00 equal to $CA 1.20. | |
Operations update
The disposition of the Permian properties in Martin County, Texas and the acquisition of the Dixonville properties in Alberta significantly changed the nature of Eagle's asset base. Forecast corporate declines have dropped from approximately 30% to under 20%, with the result being a significant reduction in required sustaining capital. As commodity prices recover, the percentage of free cash flow realized by the Trust will increase.
Eagle is well positioned to achieve full year 2015 production targets of 2,950 to 3,150 boe/d. Eagle will continue to focus on operational efficiencies and capital discipline during 2015 that lead to cost reductions.
At its Hardeman properties, Eagle has implemented a number of enhancements that have resulted in production gains. Eagle is continuing its efforts to lower operating expenses, by drilling a saltwater disposal well in the southern Hardeman operating area and installing electrical infrastructure for additional cost improvements. During the fourth quarter 2014, Eagle executed a successful two-well oil drilling program, validating its development plans for the area. Eagle is undertaking an extensive geological and geophysical review of the property in order to identify and quantify future drilling opportunities in addition to the three wells included in Eagle's 2015 capital budget.
At Salt Flat, Eagle drilled two new wells, side-tracked one existing well and installed eight horizontal pumps in existing wells to increase oil production. This work resulted in Eagle's best capital efficiency to date in the Salt Flat field. Eagle completed its planned 3-D seismic program and is currently evaluating the resulting seismic data, which is expected to optimize future drill locations in addition to the three wells already included in the 2015 capital budget and potentially identify lower zones to recover additional reserves. A combination of new wellbores and sidetracks of existing wellbores could be used to target the lower benches.
Prior to the sale of its Permian properties, Eagle drilled two new wells and recompleted eight wells. Eagle sold this property effective July 1, 2014.
On December 18, 2014, Eagle acquired a 50% non-operated working interest in the Dixonville property, located near Peace River, Alberta. The Dixonville property is a horizontal well waterflood producing from the Montney "C" oil pool and is operated by the other working interest owner. The pool is characterized by low declines, a stable production base and low ongoing capital requirements. In 2014, the field experienced two line leaks and the operator shut-in the field for a period of time. As a result, capital was directed towards a pipeline remediation program which included liner installation in the emulsion gathering system. The majority of the capital required for the remediation program was incurred prior to the January 1, 2015 effective date of the acquisition. The remaining capital is forecast to occur in the first quarter of 2015, with Eagle's share included as part of the $1.4 million capital forecast in the 2015 budget.
Year-end reserves information
Eagle targets low risk, producing properties with development potential, and maintains or grows production by converting the non-producing portion of those assets into producing assets, thereby sustaining cash flow and distributions. When the Trust makes an acquisition, it expects to record 100% of the acquired proved plus probable reserves and then develop those reserves over time, ultimately moving reserves from the probable to the proved category.
The Dixonville asset is a fully developed, long-life waterflood property. Only maintenance capital is planned for 2015 and no significant new drilling or production increases are anticipated. However, as the Dixonville asset has a very low recovery factor compared to its total booked reserves, Eagle anticipates that future capital opportunities will arise which will serve to enhance the recovery factor of the field.
An independent evaluation of the Trust's U.S. reserves was conducted by Netherland, Sewell & Associates, Inc. and of the Trust's Canadian reserves by McDaniel and Associates Consultants Ltd. These reserves evaluation reports are effective December 31, 2014 and were prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
2014 year-end reserves report - highlights
- Increased proved developed producing volumes by 88% and the value (PV10) by 29%.
- 98% of the proved developed producing reserves are light oil, 0.5% are natural gas liquids and 1.5% are natural gas.
- Closed two acquisitions, adding approximately 10.5 million boe of proved plus probable reserves and 1,300 boe/d of production at an acquisition cost, including future development costs, of approximately $14.50/boe.
- Achieved a 12% year over year increase in total proved plus probable reserves to approximately 16 million boe (71% proved, 61% proved producing).
- Improved Eagle's proved plus probable reserve life index to 14 years.
The following tables summarize the independent reserves estimates and values of Eagle's reserves as at December 31, 2014:
| Summary of reserves | ||||||||||
| Reserves category | Company Gross(1)(2) | |||||||||
| Crude Oil |
Natural Gas Liquids |
Natural Gas |
Total Oil Equivalent 2014 |
Total Oil Equivalent 2013 |
||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | (Mboe) | ||||||
| Proved | ||||||||||
| Developed producing | 9,590 | 37 | 871 | 9,773 | 5,189 | |||||
| Developed non-producing | 363 | 13 | 122 | 397 | 1,350 | |||||
| Undeveloped | 1,211 | 0 | 7 | 1,212 | 4,383 | |||||
| Total proved | 11,164 | 51 | 1,000 | 11,381 | 10,922 | |||||
| Total probable | 4,591 | 2 | 193 | 4,624 | 3,407 | |||||
| Total proved plus probable | 15,755 | 52 | 1,194 | 16,006 | 14,329 | |||||
| Notes: | |||
| (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. | ||
| (2) | Totals may not add due to rounding. | ||
| Summary of net present value of future net revenue of reserves | ||||||||||
| Reserves category | Net Present Value of Future Net Revenue(1)
Before Income Taxes Discounted at (%/year) |
|||||||||
| 0% | 5% | 10% | 15% | 20% | ||||||
| ($000's) | ($000's) | ($000's) | ($000's) | ($000's) | ||||||
| Proved | ||||||||||
| Developed producing | 389,604 | 246,797 | 180,405 | 143,665 | 120,612 | |||||
| Developed non-producing | 18,744 | 13,807 | 10,657 | 8,517 | 6,987 | |||||
| Undeveloped | 40,094 | 30,507 | 24,261 | 19,716 | 16,224 | |||||
| Total proved | 448,442 | 291,111 | 215,323 | 171,897 | 143,823 | |||||
| Total probable | 217,201 | 98,507 | 62,406 | 46,153 | 36,602 | |||||
| Total proved plus probable | 665,643 | 389,619 | 277,729 | 218,051 | 180,425 | |||||
| Notes: | |||
| (1) | 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 estimates of reserves provided in this news release are estimates only and there is no guarantee that the estimated reserves will be recovered.Actual reserves may be greater than or less than the estimates provided. | ||
At a 10% discount factor, proved developed producing reserves comprise 65% (2013 - 49%) of the total proved plus probable value. Total proved reserves account for 78% (2013 - 74%) of the total proved plus probable value.
Future development cost
Total future development costs are estimated at $26.2 million for total proved reserves and $43.0 million for total proved plus probable reserves. When compared to 2015 funds flows guidance of $29.5 million (based on $US 60 WTI oil price and a $1.25 FX rate), future development costs represent a conservative 0.9 years and 1.5 years of funds flow.
Reconciliation of Changes in Reserves
The following table set forth the reconciliation of the Trust's gross reserves as at December 31, 2014 in total.
| Reserves Reconciliation (Company Gross) |
Oil | Natural Gas Liquids |
Natural Gas |
Total | ||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | |||||||
| Total Proved | ||||||||||
| Opening Balance (Dec. 31, 2013) | 8,226 | 1,576 | 6,720 | 10,922 | ||||||
| Discoveries | 0 | 0 | 0 | 0 | ||||||
| Extensions and Improved Recovery | 377 | - | 0 | 377 | ||||||
| Technical Revisions | 551 | 17 | 32 | 573 | ||||||
| Acquisitions | 7,457 | 38 | 852 | 7,637 | ||||||
| Dispositions | (4,533) | (1,498) | (6,138) | (7,054) | ||||||
| Economic Factors | (54) | (1) | (18) | (58) | ||||||
| Production | (860) | (81) | (447) | (1,016) | ||||||
| Closing Balance (Dec. 31, 2014) | 11,164 | 51 | 1,000 | 11,381 | ||||||
| Total Probable | ||||||||||
| Opening Balance (Dec. 31, 2013) | 2,826 | 343 | 1,428 | 3,407 | ||||||
| Discoveries | 0 | 0 | 0 | 0 | ||||||
| Extensions and Improved Recovery | 593 | 0 | 0 | 593 | ||||||
| Technical Revisions | (482) | 1 | (2) | (482) | ||||||
| Acquisitions | 2,859 | 1 | 189 | 2,891 | ||||||
| Dispositions | (1,191) | (343) | (1,422) | (1,771) | ||||||
| Economic Factors | (15) | 0 | (1) | (15) | ||||||
| Production | 0 | 0 | 0 | 0 | ||||||
| Closing Balance (Dec. 31, 2014) | 4,591 | 2 | 193 | 4,624 | ||||||
| Total Proved Plus Probable | ||||||||||
| Opening Balance (Dec. 31, 2013) | 11,052 | 1,919 | 8,148 | 14,329 | ||||||
| Discoveries | 0 | 0 | 0 | 0 | ||||||
| Extensions and Improved Recovery | 970 | 0 | 0 | 970 | ||||||
| Technical Revisions | 69 | 18 | 30 | 92 | ||||||
| Acquisitions | 10,316 | 39 | 1,041 | 10,528 | ||||||
| Dispositions | (5,724) | (1,842) | (7,560) | (8,825) | ||||||
| Economic Factors | (69) | (1) | (18) | (73) | ||||||
| Production | (860) | (81) | (447) | (1,016) | ||||||
| Closing Balance (Dec. 31, 2014) | 15,755 | 52 | 1,194 | 16,006 | ||||||
Reserves performance ratios
During 2014, Eagle's capital expenditures, including acquisition capital, resulted in capital efficiency statistics as shown in the following table. Statistics which cannot be meaningfully calculated are shown as a dashed line.
| 2014 | 2013 | ||||||||
| Proved | Proved plus Probable |
Proved | Proved plus Probable |
||||||
| Reserves (Mboe) | 11,381 | 16,006 | 10,922 | 14,329 | |||||
| Capital Expenditures ($M) | |||||||||
| Exploration and Development (E&D)(1) | 13,037 | 13,037 | 30,226 | 30,226 | |||||
| Acquisition(2) | 106,319 | 106,319 | 35,855 | 35,855 | |||||
| Disposition(2) | (150,141 | ) | (150,141 | ) | - | - | |||
| Disposition (related E&D) | 11,286 | 11,286 | - | - | |||||
| Total Capital Expenditures | (19,465 | ) | (19,465 | ) | 66,081 | 66,081 | |||
| Field Netbacks ($/boe)(3) | |||||||||
| Current Year | 49.75 | 49.75 | 52.23 | 52.23 | |||||
| Three year weighted average | 49.76 | 49.76 | - | - | |||||
| Finding and Development Costs | |||||||||
| Change in future development capital ($M) | 7,165 | 14,495 | (18,567 | ) | (17,350 | ) | |||
| Reserve additions (Mboes) | 892 | 989 | (504 | ) | (2,358 | ) | |||
| F&D Costs including changes in FDC ($/boe)(5) | 22.65 | 27.85 | - | - | |||||
| F&D Costs excluding changes in FDC ($/boe)(5) | 14.62 | 13.19 | - | - | |||||
| F&D Recycle Ratio(4) | 2.20 | 1.79 | - | - | |||||
| F&D three year weighted costs ($/boe) | - | 4.79 | - | - | |||||
| F&D recycle ratio three year weighted average | - | - | - | - | |||||
| Finding, Development and Acquisition Expenditures(5) | |||||||||
| Change in future development capital ($M) | 11,535 | 18,865 | (17,339 | ) | (16,042 | ) | |||
| Reserve additions (Mboes) | 8,529 | 11,517 | 1,409 | (207 | ) | ||||
| FD&A Costs including changes in FDC ($/boe)(5) | 15.35 | 12.00 | 34.59 | - | |||||
| FD&A Costs excluding changes in FDC ($/boe)(5) | 13.99 | 10.36 | 46.90 | - | |||||
| FD&A Recycle Ratio(4) | 3.24 | 4.15 | 1.51 | - | |||||
| FD&A three year weighted costs ($/boe) | 26.69 | - | - | - | |||||
| FD&A recycle ratio three year weighted average | 2.11 | 1.94 | - | - | |||||
| Reserves replacement(6) | 145 | % | 265 | % | 128 | % | - | ||
| Reserves life index (yrs)(7) | 10.2 | 14.4 | 8.9 | 11.7 | |||||
| Notes: | |||
| (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 relates to the December 2014 asset acquisition in Dixonville. Disposition relates to the August 2014 divestiture of the Permian properties. | ||
| (3) | Field netbacks are calculated by subtracting royalties and operating costs from revenues. | ||
| (4) | The recycle ratio is calculated using Eagle's 2014 field netback of $49.75 per boe (2013 - $52.23 per boe) and dividing that number by the FD&A costs per boe. | ||
| (5) | Eagle calculates finding and development ("F&D") and finding, development and acquisition ("FD&A") costs, incorporating both the costs and associated reserve additions related to development capital and acquisitions during the year. Both the F&D and the FD&A calculations shown exclude the Permian disposition and Permian development capital spent during 2014.As the Permian property was sold mid-year, no independent reserve assessment was prepared to provide the reserve additions related to the capital that was spent on the Permian property in 2014, therefore the F&D calculation cannot be accurately calculated.In addition, as the proceeds of the Permian disposition exceeded the acquisition costs, including the disposition in the FD&A would have resulted in a negative number.Since acquisitions have a significant impact on Eagle's annual reserve replacement costs, Eagle believes that the FD&A costs shown, excluding the Permian disposition, provide a more meaningful portrayal of Eagle's cost structure. | ||
| (6) | The reserves replacement ratios are calculated by dividing total reserve additions by total working interest production for the year. | ||
| (7) | The 2014 reserve life index calculation is based on the mid-point of Eagle's 2015 average working interest production guidance of 3,050 boe/d and the 2013 reserve life index calculation was based on 3,350 boe/d. | ||
Selected annual information
The following table shows selected information for the Trust's fiscal year ended December 31, 2014, December 31, 2013 and December 31, 2012.
| Year ended December 31 | 2014 | 2013 | 2012 | |||||
| ($000's except per unit amounts and production) | ||||||||
| Sales volumes - boe/d | 2,782 | 3,004 | 2,596 | |||||
| Revenue, net of royalties | 67,175 | 69,210 | 56,997 | |||||
| Field netback | 50,522 | 57,260 | 44,962 | |||||
| Funds flow from operations | 33,958 | 44,271 | 35,298 | |||||
| per unit - basic | 1.01 | 1.44 | 1.43 | |||||
| per unit - diluted | 1.00 | 1.44 | 1.33 | |||||
| Earnings (loss) | (48,028 | ) | 4,914 | 6,117 | ||||
| per unit - basic | (1.43 | ) | 0.16 | 0.25 | ||||
| per unit - diluted | (1.55 | ) | 0.16 | 0.24 | ||||
| Current assets | 33,245 | 9,889 | 14,464 | |||||
| Current liabilities | 10,720 | 30,461 | 17,512 | |||||
| Total assets | 257,172 | 335,679 | 284,802 | |||||
| Total non-current liabilities | 57,547 | 70,521 | 42,111 | |||||
| Unitholders' equity | 188,905 | 234,697 | 225,179 | |||||
| Distributions declared | 33,524 | 32,434 | 26,816 | |||||
| per issued unit | 0.99 | 1.05 | 1.05 | |||||
| Units outstanding for accounting purposes | 35,017 | 32,149 | 29,269 | (1) | ||||
| Units issued | 35,017 | 32,149 | 29,374 | |||||
| Notes: | |||
| (1) | Units outstanding for accounting purposes exclude 105,417 units issued due to the performance conditions that had to be met to enable such units to be released from escrow. | ||
| Summary of quarterly results | ||||||||||||||
Q4/2014 |
Q3/2014 | Q2/2014 | Q1/2014 | Q4/2013 | Q3/2013 | Q2/2013 | Q1/2013 | |||||||
| ($000's except for boe/d and per unit amounts) | ||||||||||||||
| Sales volumes - boe/d | 1,929 | 2,859 | 3,341 | 3,010 | 2,994 | 3,052 | 3,022 | 2,928 | ||||||
| Revenue, net of royalties | 10,238 | 17,143 | 20,821 | 18,973 | 17,119 | 19,046 | 16,698 | 16,346 | ||||||
| per boe | 57.67 | 65.19 | 68.48 | 70.04 | 62.15 | 67.84 | 60.73 | 62.03 | ||||||
| Field netback | 6,841 | 12,832 |
16,144 | 14,705 | 13,106 | 15,945 | 14,352 | 13,857 | ||||||
| per boe | 38.54 | 48.80 | 53.10 | 54.29 | 47.58 | 56.79 | 52.20 | 52.59 | ||||||
| Funds flow from operations | 5,670 | 7,476 | 10,471 | 10,341 | 8,794 | 11,615 | 11,977 | 11,884 | ||||||
| per boe | 31.94 | 28.43 | 34.44 | 38.18 | 31.93 | 41.37 | 43.56 | 45.10 | ||||||
| per unit - basic | 0.16 | 0.22 | 0.32 | 0.32 | 0.28 | 0.37 | 0.39 | 0.40 | ||||||
| per unit - diluted | 0.15 | 0.16 | 0.28 | 0.25 | 0.28 | 0.37 | 0.39 | 0.40 | ||||||
| Earnings (loss) | (35,192 | ) | 8,104 | (23,158 | ) | 2,218 | 156 | (3,241 | ) | 3,919 | 4,080 | |||
| per unit - basic | (1.01 | ) | 0.24 | (0.70 | ) | 0.07 | 0.00 | (0.10 | ) | 0.13 | 0.14 | |||
| per unit - diluted | (1.13 | ) | 0.18 | (0.70 | ) | 0.02 | 0.00 | (0.10 | ) | 0.13 | 0.14 | |||
| Cash distributions declared | 7,159 | 9,036 | 8,775 | 8,555 | 8,376 | 8,204 | 8,026 | 7,828 | ||||||
| per issued unit | 0.2050 | 0.2625 | 0.2625 | 0.2625 | 0.2625 | 0.2625 | 0.2625 | 0.2625 | ||||||
| Current assets | 33,245 | 76,566 | 8,802 | 9,116 | 9,889 | 9,950 | 11,443 | 9,913 | ||||||
| Current Liabilities | 10,720 | 13,587 | 32,878 | 33,348 | 30,461 | 20,942 | 19,874 | 11,982 | ||||||
| Total assets | 257,172 | 240,458 | 320,182 | 356,332 | 335,679 | 306,021 | 311,271 | 283,112 | ||||||
| Total non-current liabilities | 57,547 | 2,565 | 80,126 | 79,684 | 70,521 | 55,069 | 50,654 | 39,873 | ||||||
| Unitholders' equity | 188,905 | 224,306 | 207,178 | 243,300 | 234,697 | 230,010 | 240,743 | 231,257 | ||||||
| Units outstanding for accounting purposes | 35,017 |
34,821 | 33,739 | 32,836 | 32,149 | 31,469 | 30,707 | (1) | 29,260 | (1) | ||||
| Units issued | 35,017 | 34,821 | 33,739 | 32,836 | 32,149 | 31,469 | 30,813 | 30,066 | ||||||
| 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. | ||
Funds flow from operations is a non-IFRS financial measure. See "Non-IFRS financial measures".
For the three months ended December 31, 2014, sales volumes decreased 33% compared to the previous quarter because fourth quarter sales volumes reflect the full quarter impact of the Permian property disposition on August 29, 2014. Prior to the third quarter 2014, with the exception of the fourth quarter 2013, which encountered non-recurring weather related delays and non-owned infrastructure problems, production has generally increased commensurate with well tie-ins and acquisitions. See "Activity summary" and "Capital expenditures".
Funds flow from operations decreased in the fourth quarter of 2014 when compared to the prior quarter due to weaker commodity prices, the disposition of the Permian property, and additional administrative expenses typical for the fourth quarter. Fourth quarter 2014 funds flow from operations was further tempered by one-time transaction costs associated with the acquisition of the Dixonville property including the special meeting of the unitholders. Generally, in times of steady or increasing prices, funds flow from operations per boe increases when sales volumes increase and decreases when sales volumes decrease. This is because certain expenses tend to be more fixed in nature (such as operating costs, and 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 non-cash items that factor into the calculation of income (loss), and other items which are required to be fair valued at each quarter end. By way of example, fourth quarter 2014 funds flow from operations decreased 24% from the third quarter while the absolute swing from third quarter income to a fourth quarter loss was by a much larger percentage. This occurred because an impairment charge was recognized on Eagle's oil and gas assets in relation to its Salt Flat properties. The effect of the impairment charge was slightly offset by a weaker forward commodity price environment that increased the fourth quarter fair market valuation of Eagle's forward commodity contracts, and the lower unit price at the end of the fourth quarter of 2014 that caused a higher unit-based compensation recovery to be recorded upon performing a fair market valuation of future unit-based payments.
| Activity summary | ||||||||
| Wells drilled (rig-released) | Three Months Ended December 31, 2014 |
Three Months Ended December 31, 2013 |
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |
| Salt Flat | - | 1 | 1.0 | 3 | 2.4 | 7 | 6.2 | |
| Permian | - | - | - | 2 | 2.0 | 5 | 5.0 | |
| Hardeman | 2 | 2.0 | - | - | 2 | 2.0 | - | - |
| Total | 2 | 2.0 | 1 | 1.0 | 7 | 6.4 | 12 | 11.2 |
| Wells brought on-stream | Three Months Ended December 31, 2014 |
Three Months Ended December 31, 2013 |
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |
| Salt Flat | - | - | - | - | 3 | 2.4 | 6 | 5.2 |
| Permian | - | - | - | - | 2 | 2.0 | 6 | 6.0 |
| Hardeman | 2 | 2.0 | - | - | 2 | 2.0 | - | - |
| Total | 2 | 2.0 | - | - | 7 | 6.4 | 12 | 11.2 |
Refer to the "Operations update" section at the beginning of this news release.
Capital expenditures
Capital spending during the quarter and year ended December 31, 2014 and December 31, 2013 was as follows:
| Three Months Ended December 31, 2014 |
Three Months Ended December 31, 2013 |
Year Ended December 31, 2014 |
Year Ended December 31, 2013 |
|||||||||
| (000's) | $ | $ | $ | $ | ||||||||
| Exploration and evaluation(1) | (16 | ) | - | - | 63 | |||||||
| Acquisition - Hardeman 2013 | - | 27,087 | - | 27,087 | ||||||||
| Acquisition - Hardeman 2014 | - | - | 5,409 | - | ||||||||
| Acquisition - Permian - 7.5% interest | - | (62 | ) | - | 8,768 | |||||||
| Disposition - Permian | 6 | - | (150,141 | ) | - | |||||||
| Acquisition - Dixonville | 100,910 | - | 100,910 | - | ||||||||
| Intangible drilling and completions | 2,892 | 1,017 | 18,194 | 26,198 | ||||||||
| Seismic | 458 | 3,742 | ||||||||||
| Well equipment and facilities | 859 | 388 | 2,360 | 3,856 | ||||||||
| Proceeds from disposal of assets | - | (106 | ) | - | (106 | ) | ||||||
| Other | 10 | 18 | 61 | 215 | ||||||||
| $ | 105,119 | $ | 28,342 | $ | (19,465 | ) | $ | 66,081 | ||||
| Note: | |||
| (1) | Exploration and evaluation expenditures relate to amounts spent on land to which no proven reserves are yet assigned. | ||
During the fourth quarter of 2014, the Trust spent $3.7 million on drilling, completions, tie-ins and recompletions. Of this total, $3.3 million was spent to drill and tie-in two Hardeman wells and $0.4 million to recomplete existing wells in Hardeman and Salt Flat. In addition, $0.5 million was spent for seismic processing in the Hardeman properties. Refer to the "Operations update" section of this news release.
Eagle is well positioned for growth with financial flexibility and operational strength. The Trust intends to continue to actively pursue acquisitions in the U.S. and Canada.
Property acquisitions
Dixonville property
On December 18, 2014, the Trust's newly established Canadian operating subsidiary, Eagle Energy Canada Inc., acquired a 50% non-operated working interest in producing properties in the Dixonville Montney "C" oil pool located in north central Alberta for cash consideration of $100.9 million, which includes preliminary closing adjustments of $909,620. The closing adjustments are subject to change. The acquisition established a new strategic Canadian property and diversified the Trust's portfolio of petroleum assets.
Consideration consisted of cash. The acquisition has been accounted for as a business combination with the fair value of the net assets as follows:
| Identifiable assets acquired and liabilities assumed ($CA): | ||||
| Oil and gas properties | $ | 101,294 | ||
| Decommissioning liabilities | (384 | ) | ||
| $ | 100,910 | |||
Hardeman properties
On February 27, 2014, the Trust's U.S. operating subsidiary acquired undeveloped acreage and an average 66% working interest in producing properties in Hardeman County, Texas and in Greer, Harmon and Jackson counties, Oklahoma for cash consideration of $5.4 million. The acquisition increased Eagle's established position in Hardeman County.
Consideration consisted of cash. The acquisition has been accounted for as a business combination with the fair value of the net assets as follows:
| Identifiable assets acquired and liabilities assumed ($CA): | ||||
| Oil and gas properties | $ | 5,497 | ||
| Decommissioning liabilities | (88 | ) | ||
| $ | 5,409 | |||
Property disposition
Permian property
On August 29, 2014, the Trust's U.S. operating subsidiary closed the sale of its entire working interest in oil and natural gas properties in the Permian Basin, located near Midland, Texas, for net proceeds of $150.1 million ($US 140 million) after closing adjustments. Prior to its disposition the Trust recognized an impairment charge on the asset, reducing its carrying value to its net realizable value. Accordingly, no gain or loss was recorded on the sale.
Proceeds consisted of cash. The disposition has been accounted for as follows:
| Identifiable assets and liabilities disposed of ($CA): | ||||
| Oil and gas properties | $ | 151,330 | ||
| Decommissioning liabilities | (1,189 | ) | ||
| $ | 150,141 | |||
Non-IFRS financial measures
Statements throughout this news release make reference to the terms "field netback", "funds flow from operations", "free cash flow", "basic payout ratio" and "corporate payout ratio", which are non-International Financial Reporting Standards ("IFRS") financial measures that do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers. Management believes that these terms 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. "Free cash flow" is calculated by subtracting capital expenditures from field netbacks for the property. "Basic payout ratio" and "corporate payout ratio" are calculated as set forth under "2015 Budget and Outlook - Calculations regarding Eagle's distributions". See the "Non-IFRS financial measures" section of the management discussion and analysis for a reconciliation of funds flow from operations and field netback to earnings (loss) for the period, the most directly comparable measure in the Trust's audited annual consolidated financial statements. 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 news 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 news release. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.
In particular, and without limitation, this news release contains forward looking statements pertaining to the following:
- Eagle's 2015 capital and operating budget and specific uses, including Eagle's 2015 drilling plans and potential locations;
- Eagle's expectations regarding its 2015 average working interest production, operating costs, field netbacks, corporate decline rate and funds flow from operations;
- Eagle's expectation that as commodity prices recover the percentage of free cash flow realized by the Trust will increase;
- Eagle's expectation that it is well positioned to achieve full year 2015 production targets and that its continued focus on operational efficiencies and capital discipline will lead to cost reductions;
- Eagle's expectation that its 2015 budget should be sufficient to sustain production levels and add a designated component of growth-focused capital;
- Eagle's projected payout ratios and the sensitivities of funds flow and payout ratios to changes in production rates, exchange rates and commodity prices;
- Management's view in respect of Eagle's financial flexibility, operational strength and sustainability, and the Trust's intention to continue to actively pursue acquisitions in the U.S. and Canada;
- projected amount of and sustainability of distributions on the Units;
- projected percentage weighting of oil, gas and NGLs in 2015 production;
- existing credit facilities and the availability of new credit facilities to fund acquisitions;
- projected debt to trailing cash flow;
- estimated reserve life index;
- Eagle's expectation that, on its Dixonville asset, future capital opportunities will arise which will serve to enhance the recovery factor of the field;
- Eagle's business model with respect to acquisitions and reserves booking; and
- estimated volumes and value of Eagle's reserves.
With respect to forward-looking statements contained in this news release, assumptions have been made regarding, among other things:
- future oil, natural gas and NGL prices and weighting;
- future currency exchange rates;
- the regulatory framework governing taxes in the US and Canada and the Trust's status as a "mutual fund trust" and a "SIFT trust";
- future production levels;
- future recoverability of reserves;
- future capital expenditures and the ability of the Trust to obtain financing on acceptable terms for its capital projects and future acquisitions;
- future distributions levels;
- the Trust's 2015 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;
- the ability of the Trust to compete for new acquisitions;
- 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; and
- the accuracy of the estimates of Eagle's reserves volumes and values.
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 included in the Trust's Annual Information Form for the year ended December 31, 2014 ("AIF") available on SEDAR at www.sedar.com:
- volatility of oil, natural gas and NGL prices;
- changes in 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;
- availability of financing and capital;
- the regulatory framework governing taxes in the U.S. and Canada and the Trust's status as a "mutual fund trust": and a "SIFT" trust; 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 Trust's AIF under the heading "Risk Factors".
As a result of these risks, actual performance and financial results in 2015 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, 2015 capital budget, funds flow, field netbacks, decline rates, reserves volumes and values, and the Trust's distributions are subject to change in light of ongoing results, prevailing economic circumstances, obtaining regulatory approvals, commodity prices, exchange rates 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 news 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 sustainable business while delivering moderate growth in production and overall growth through accretive acquisitions. Eagle's units are traded on the Toronto Stock Exchange under the symbol EGL.UN.
All material information about Eagle may be found on its website at www.eagleenergytrust.com or under Eagle's issuer profile at www.sedar.com.
Contact Information:
Kelly Tomyn
Chief Financial Officer
(403) 531-1574
ktomyn@eagleenergytrust.com
Eagle Energy Inc.
Richard W. Clark
President and Chief Executive Officer
(403) 531-1575
rclark@eagleenergytrust.com
Eagle Energy Inc.
Suite 2710, 500-4th Avenue SW
Calgary, Alberta T2P 2V6
(403) 531-1575
(855) 531-1575 (toll free)
info@eagleenergytrust.com