CALGARY, ALBERTA--(Marketwired - March 21, 2014) - Eagle Energy Trust (the "Trust" or "Eagle") (TSX:EGL.UN) is pleased to report its financial and operating results for the three months and year ended December 31, 2013 and its 2013 reserves information.
"2013 was a successful year for Eagle," said Richard Clark, the Trust's President and CEO. "We increased our proved developed producing reserves by 14%, met our production guidance, averaged 3,000 boe per day of production, improved our field netbacks to over $52.00 per boe and maintained a prudent balance sheet."
Mr. Clark continued, "Eagle's strong asset base positions the Trust for continued growth. We are well positioned to capitalize on the upside of our Permian properties and our newly acquired assets in Hardeman County, Texas. I am pleased with the performance of our operations team, led by Wayne Wisniewski, in meeting production targets and reducing overall operating costs per boe by 12%."
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.
In addition, the Trust has posted video commentary from management regarding its operations and the annual financial results on its website at the following link: http://www.eagleenergytrust.com/videos.
This press release contains statements that are forward looking. Investors should read the Note Regarding Forward Looking Statements at the end of this news release.
Highlights for the year ended December 31, 2013
- Reported a 16% year-over-year increase in working interest sales volumes, to average 3,004 barrels of oil equivalent per day ("boe/d") (82% oil, 10% natural gas liquids ("NGLs"), 8% natural gas).
- Achieved a 12% year-over-year reduction in per boe operating expenses from $14.48 to $12.73.
- Generated a 10% year-over-year increase in field netbacks, to average $52.23 per boe. Eagle realized an average oil price of $102.93 per barrel during this period, based on the WTI benchmark average for the year of $US 97.98.
- Delivered a 25% year-over-year increase in funds flow from operations to $44.3 million ($40.38 per boe or $1.44 per unit).
- Added a third core area in November 2013 by acquiring 7,920 (7,395 net) undeveloped acres and operated properties producing 300 boe per day (97% oil) in Hardeman County, Texas for cash consideration of $27.1 million.
- Continued to manage Eagle in a financially prudent manner, with 2013 year-end debt to trailing cash flow of 1.7x (1.5x if the December 2013 cash flow from the November 2013 Hardeman acquisition is annualized).
- Created a 14% year-over-year increase in proved development producing reserves both in net present value discounted at 10% ("PV10") and volume, which was essentially level on a per-unit basis.
- Achieved a 19% year-over-year increase in the value of total proved reserves (PV10) and a 3% increase in volumes. Total proved reserves were essentially level on a per-unit basis.
- Maintained 2013 unitholder distributions steady at $1.05 per unit ($0.0875 per unit per month).
Acquisition in early 2014
Subsequent to year end, on February 27, 2014, the U.S. subsidiary of the Trust acquired additional undeveloped acreage and an average 66% working interest in producing properties in Hardeman County, Texas, and Greer, Harmon and Jackson Counties, Oklahoma for a net purchase price of $US 4.7 million. Through this small tuck-in acquisition, Eagle acquired interests in 13 (5.4 net) producing wells. The sellers' working interest production at the date of the acquisition was approximately 130 boe per day for a purchase price metric of $US 36,000 per flowing boe/d. The Trust used an advance under its credit facility to fund the acquisition.
For 2014, the Trust has chosen to keep its $US 28.0 million capital budget unchanged, and has reduced its planned drilling program by the amount of this $US 4.7 million acquisition. With the incremental production from this acquisition replacing the production from those wells that were removed from the drilling program, 2014 guidance for average working interest production, operating costs and cash flow remain unchanged. See the "2014 Outlook" section of this news release.
Management's commentary on achievement of 2013 guidance
The following shows how Eagle's 2013 results performed compared to its latest published 2013 guidance:
- Average working interest sales volumes of 3,004 boe/d was in the mid-range of the 2,900 to 3,100 boe/d guidance. With January 2014 average working interest production of approximately 3,000 boe/d, Eagle is well positioned to achieve 2014 production targets of 3,250 to 3,450 boe/d.
- Full year average operating costs were $12.73 per boe, compared to $12.00 per boe operating cost guidance.
- Full year funds flow from operations of $44.3 million, which was 98% of guidance.
- Full year capital expenditures, excluding acquisitions, were $US 29.3 million and in line with guidance at $US 29.2 million.
- 2013 year-end debt to trailing cash flow ratio of approximately 1.7x includes the late November 2013 Hardeman acquisition for $27.1 million, which, if removed from debt, results in year-end debt to trailing cash flow of 1.1x, approximating guidance of 1.03x.
- Full year basic payout ratio of 74% (derived by dividing unitholder distributions into funds flow from operations) compared to guidance of 72%.
Operations update
With January 2014 average working interest production of approximately 3,000 boe/d, Eagle is well positioned to achieve full year 2014 production targets of 3,250 to 3,450 boe/d and poised to add additional production and reserves with the start of its capital program. As was demonstrated in 2013, Eagle will continue to focus on operational efficiencies during 2014 that lead to lower operating expenses.
At its newly acquired Hardeman property, Eagle has implemented enhancements that have resulted in production gains and plans to lower operating expenses by drilling saltwater disposal wells and using lease gas as fuel.
At its Salt Flat properties, two new wells have been drilled and completed, with plans to install horizontal pumps in certain existing wells to increase oil production. Eagle also plans to conduct a 3-D seismic program once the necessary permits are obtained. The resulting seismic data is expected to delineate the geologic complexity of the field, optimize future drill locations and potentially identify lower zones to recover bypassed oil that is not being drained by current wellbores.
At its Permian properties, Eagle's plans are to drill new wells and recomplete multiple new zones to obtain additional production from existing wellbores. To date, the first well of the recompletion program has met expectations and is on track. The new wells will be drilled in sequence with the first one commencing in March 2014.
Management's commentary on reserves
Eagle predominantly acquires 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.
During 2013, Eagle closed two acquisitions, adding 2.2 million boe at a total proved plus probable acquisition cost (including future development costs) of $17.28 per boe.
Proved reserves
Proved reserves are critical to the sustainability of the Trust's cash flow and distribution payments. In 2013, Eagle added 1.9 million boe of proved reserves through acquisitions and 0.7 million boe through drilling. These proved reserves additions were offset by production and technical revisions of 2.3 million boe.
Probable reserves
The Trust's business model is to expect at best a moderate increase in proved plus probable reserves bookings, without new acquisitions. On its existing Salt Flat properties, Eagle did not anticipate significant probable reserve additions as the Salt Flat property has transitioned from growth mode to harvest mode, meaning less than half of the property's cash flow needs to be reinvested to replace declines.
This year, Eagle consolidated its external reserves evaluation into its existing US-based reserves evaluation firm in order to gain the greatest access to local Permian Basin expertise and data. Based on the most current data from the performance of Eagle's wells over time, that firm has chosen to revise Eagle's reserves estimates in both Salt Flat and Permian properties.
Eagle expects the emerging horizontal play on its Permian property to add future reserves, although it is too early for Eagle to book reserves estimates for this play. Eagle continues to monitor Permian horizontal drilling activity in the area while the play is de-risked by other operators. Eagle believes a longer production history for these wells will ultimately allow reserves to be booked that are representative of the potential of these wells. For these reasons, Eagle elected not to include any locations or value for potential horizontal wells in its 2013 reserves evaluation.
Eagle achieved the following for its 2013 reserves:
- Maintained a corporate reserve life index of approximately 12 years.
- Increased by 19% the year-over-year value of total proved reserves.
- Increased by 14% the year-over-year value and volume of proved developed producing reserves.
Eagle continues to manage its operations in a financially prudent manner, preserve sufficient liquidity, and maintain a strong balance sheet. No balance sheet impairment provision was recognized on its oil and gas properties for 2013, underpinning Management's view that the fair value of its portfolio of properties has not changed.
2014 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 2014. 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".
On December 17, 2013, the Board of Directors approved a 2014 capital budget of $US 28.0 million. Of this amount, $US 3.8 million will be directed towards land acquisition and seismic evaluation of future opportunities in Eagle's areas of operations, with the remaining $US 24.2 million base investment used to replace declines and grow 2014 annual working interest production and funds flow by approximately 10% over 2013.
As a result of its February 2014 tuck-in acquisition for $US 4.7 million in Hardeman County, the Trust has chosen to keep its $US 28.0 million capital budget unchanged and has reduced its planned drilling program by the amount of this $US 4.7 million acquisition. With the incremental production from this acquisition replacing the production from those wells that were removed from the drilling program, 2014 guidance for average working interest production, operating costs and cash flow remain unchanged.
For 2014, Eagle's budget continues to focus on asset development in Texas and to continue to move its assets in the Permian and Hardeman basins towards the sustainability phase. It also includes capital for the newly acquired Hardeman properties to define future development potential.
With this 2014 capital budget, Eagle intends to execute an 7 (6.2 net) well drilling program on its Salt Flat, Permian and Hardeman properties as well as embarking on recompletions, facilities upgrades and debottlenecking across its portfolio. In addition, a portion of the capital investment will be deployed to purchase land and evaluate seismic opportunities.
Eagle anticipates that its average 2014 working interest production will be in the range of 3,250 to 3,450 boe/d (up 10% year-over-year), consisting of 85% oil, 9% NGLs and 6% gas.
Operating costs per boe (inclusive of transportation) in 2014 are expected to average from $12.50 to $14.50 per boe, resulting in field netbacks of approximately $52.00 per boe.
Funds flow from operations in 2014 is expected to be approximately $49.1 million using the following assumptions:
- average working interest production of 3,350 boe/d (being the midpoint of the guidance range);
- pricing at $US 95.00 per barrel WTI oil, $US 3.35 per Mcf NYMEX gas and $US 33.25 per barrel NGLs (NGLs price is calculated as 35% of the WTI price);
- differential to WTI (excluding transportation) of a discount of $US 1.17 per barrel for the Permian properties, $US 2.52 per barrel for the Salt Flat properties, and $US 2.40 per barrel for the Hardeman properties;
- average operating costs (inclusive of transportation) of $13.50 per boe; and
- foreign exchange rate of $CA 1.05 = $US 1.00.
A table showing the sensitivity of Eagle's funds flow to production and commodity pricing is set out below under the heading "2014 Sensitivities".
2014 Capital budget
The Board of Directors has approved a 2014 capital budget of $US 28 million, consisting of the following drilling plans:
- Salt Flat properties:
- 4 (3.2 net) horizontal oil wells
- Land, seismic, other projects
- Permian properties:
- 2 (2.0 net) vertical wells
- 10 to 15 recompletions, capital workovers and other projects
- Hardeman properties:
- 1 (1.0 net) vertical wells
- 1 to 3 recompletions, capital workovers, seismic and other projects
The capital budget includes the February 2014 tuck-in acquisition in Hardeman County for $US 4.7 million and associated production.
Calculations and commentary regarding the sustainability of Eagle's distributions
The following table sets out Eagle's 2014 guidance with respect to its projected payout ratios, debt to trailing cashflow and percentage drawn on its credit facility.
| 2014 Guidance | Notes | ||
| Payout ratios (as a percentage of cash flow) | |||
| Basic payout ratio (i.e., distribution) | 72% | (1) | |
| Plus: capital expenditures (excluding "E" capital) | 52% | (2) | |
| Equals: corporate payout ratio | 123% | (3) | |
| Adjusted payout ratio (i.e., distribution - DRIP proceeds + capital expenditures) | 77% | (4) | |
| Financial strength | |||
| Debt to trailing cashflow | 1.34x | (5) | |
| % drawn on existing credit facility | 78% | (5) | |
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 "2014 Sensitivities".
(2) Approximately $US 3.75 million of the 2014 capital budget will be directed towards land and seismic evaluation of opportunities in Eagle's areas of operation ("E" capital), and is excluded from this calculation.
(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 "2014 Sensitivities".
(4) Assumes 65% unitholder participation in Eagle's Premium DRIP™ and distribution reinvestment programs is unchanged throughout 2014. 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) The total borrowing base under the credit facility is $US 90 million.
Underlying asset quality benchmarks
Eagle's underlying asset base has the following inherent attributes:
| Oil and gas fundamentals | 2014 Guidance | Notes | |
| Oil weighting | 85% | ||
| Gas weighting (@ 6 Mcf:1bbl) | 6% | ||
| NGL weighting | 9% | ||
| Operating expense | $12.50 to $14.50 | (1) | |
| Field netbacks | $52.00 | (2) | |
| % hedged | 49% | (3) | |
Notes:
(1) Includes transportation.
(2) Directly relates to producer's ability to generate free cash flow. Assuming average operating costs (inclusive of transportation) of $13.50 per boe.
(3) Hedging supports sustainability in a volatile commodity price environment (target 50%). 2014 hedges currently in place lock in an average of 1,650 barrels per day at WTI prices ranging from $US 90.00 to $US 98.00 per barrel.
2014 Sensitivities
The following tables show the sensitivity of Eagle's funds flow, corporate payout ratio and basic payout ratio to changes in commodity price and production.
Sensitivity of funds flow ($ millions) to commodity price and production
| 2014 Average WTI | ||||
| $US 90.00 | $US 95.00 | $US 100.00 | ||
| 2014 average working interest production (boe/d) | 3,250 | 45.6 | 47.2 | 48.3 |
| 3,350 | 47.4 | 49.1 | 50.4 | |
| 3,450 | 49.2 | 51.1 | 52.4 | |
Sensitivity of corporate payout ratio to commodity price and production
| 2014 Average WTI | ||||
| $US 90.00 | $US 95.00 | $US 100.00 | ||
| 2014 average working interest production (boe/d) | 3,250 | 132% | 129% | 125% |
| 3,350 | 128% | 123% | 120% | |
| 3,450 | 123% | 118% | 115% | |
Sensitivity of basic payout ratio to commodity price and production
| 2014 Average WTI | ||||
| $US 90.00 | $US 95.00 | $US 100.00 | ||
| 2014 average working interest production (boe/d) | 3,250 | 77% | 74% | 73% |
| 3,350 | 74% | 72% | 70% | |
| 3,450 | 71% | 69% | 67% | |
Assumptions:
(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 $13.50 per boe.
(4) Approximately $US 3.8 million of the 2014 capital budget will be directed towards land and seismic evaluation of opportunities in Eagle's areas of operation, and is excluded from this calculation.
Selected annual information
The following table shows selected information for the Trust's fiscal year ended December 31, 2013, December 31, 2012 and December 31, 2011.
| Year ended December 31 | 2013 | 2012 | 2011 | |
| ($000's except per unit amounts and production) | ||||
| Sales volumes - boe/d | 3,004 | 2,596 | 1,376 | |
| Revenue, net of royalties | 71,217 | 58,724 | 31,771 | |
| Field netback | 57,260 | 44,962 | 25,150 | |
| Funds flow from operations | 44,271 | 35,298 | 19,853 | |
| per unit - basic | 1.44 | 1.43 | 1.11 | |
| per unit - diluted | 1.44 | 1.33 | 1.11 | |
| Income (loss) | 4,914 | 6,117 | (1,213) | |
| per unit - basic | 0.16 | 0.25 | (0.07) | |
| per unit - diluted | 0.16 | 0.24 | (0.07) | |
| Current assets | 9,889 | 14,464 | 13,386 | |
| Current liabilities | 30,461 | 17,512 | 16,557 | |
| Total assets | 335,679 | 284,802 | 158,885 | |
| Total non-current liabilities | 70,521 | 42,111 | 502 | |
| Unitholders' equity | 234,697 | 225,179 | 141,826 | |
| Distributions declared | 32,434 | 26,816 | 19,287 | |
| per issued unit | 1.05 | 1.05 | 1.05 | |
| Units outstanding for accounting purposes | 32,149 | 29,269(2) | 18,544(1) | |
| Units issued | 32,149 | 29,374 | 18,931 | |
Notes:
(1) Units outstanding for accounting purposes exclude 387,000 units issued due to the performance conditions that had 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 had to be met to enable such units to be released from escrow.
Summary of quarterly results
Q4/2013 |
Q3/2013 | Q2/2013 | Q1/2013 | Q4/2012 | Q3/2012 | Q2/2012 | Q1/2012 | |
| ($000's except for boe/d and per unit amounts) | ||||||||
| Sales volumes - boe/d | 2,994 | 3,052 | 3,022 | 2,928 | 2,986 | 2,825 | 2,400 | 2,169 |
| Revenue, net of royalties per boe |
17,733 64.37 |
19,517 69.51 |
17,162 62.42 |
16,805 63.77 |
16,519 60.13 |
15,181 58.41 |
13,077 59.90 |
13,947 70.67 |
| Funds flow from operations per boe per unit - basic per unit - diluted |
8,794 31.93 0.28 0.28 |
11,615 41.37 0.37 0.37 |
11,977 43.56 0.39 0.39 |
11,884 45.10 0.40 0.40 |
9,905 36.06 0.34 0.32 |
9,039 34.78 0.32 0.32 |
7,233 33.13 0.31 0.31 |
9,118 46.20 0.50 0.50 |
| Income (loss) per unit - basic & diluted |
156 0.00 |
(3,241) (0.10) |
3,919 0.13 |
4,080 0.14 |
(403) (0.02) |
(1,095) (0.04) |
8,567 0.37 |
(952) (0.05) |
| Distributions declared per issued unit |
8,376 0.2625 |
8,204 0.2625 |
8,026 0.2625 |
7,828 0.2625 |
7,653 0.2625 |
7,512 0.2625 |
6,628 0.2625 |
5,024 0.2625 |
| Current assets | 9,889 | 9,950 | 11,443 | 9,913 | 14,464 | 14,209 | 18,758 | 16,447 |
| Current liabilities | 30,461 | 20,942 | 19,874 | 11,982 | 17,512 | 23,723 | 28,158 | 20,319 |
| Total assets | 335,679 | 306,021 | 311,271 | 283,112 | 284,802 | 283,913 | 291,273 | 156,477 |
| Total non-current liabilities | 70,521 | 55,069 | 50,654 | 39,873 | 42,111 | 35,136 | 27,192 | 489 |
| Unitholders' equity | 234,697 | 230,010 | 240,743 | 231,257 | 225,179 | 225,055 | 235,923 | 135,669 |
| Units outstanding for accounting purposes | 32,149 |
31,469 |
30,707(1) | 29,960(1) | 29,269(1) | 28,654(1) | 27,895(1) | 18,847(1) |
| Units issued | 32,149 | 31,469 | 30,813 | 30,066 | 29,375 | 28,783 | 28,283 | 19,234 |
Note:
(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.
Funds flow from operations is a non-IFRS financial measure. See "Non-IFRS financial measures".
Sales volumes in the fourth quarter were slightly below third quarter 2013 levels due to non-recurring weather related and non-owned infrastructure problems. Refer to the sections of this press release titled "Capital expenditures", "Acquisitions" and "Activity Summary".
Funds flow from operations decreased in the fourth quarter of 2013, when compared to the prior quarter due to weaker commodity prices, non-recurring well workover costs and additional administrative expenses typical for the fourth quarter. 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. 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 2013 funds flow from operations decreased 24% from the third quarter while the fourth quarter loss decreased by 93%. This occurred for two reasons. First, a weakened forward commodity price environment raised the fair market valuation of Eagle's forward commodity contracts. Second, a lower year end unit price caused a lower fourth quarter expense to be recorded in the income statement upon performing a fair market valuation of future unit based payments.
Total current and non-current liabilities increased in the fourth quarter of 2013 compared to the third quarter of 2013 as a result of increased borrowing to fund the acquisition of the Hardeman property on November 25, 2013.
Activity summary
| Wells Drilled | Three Months Ended December 31, 2013 |
Three Months Ended December 31, 2012 |
Year Ended December 31, 2013 |
Year Ended September 30, 2012 |
||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |
| Salt Flat | 1 | 1.0 | 4 | 3.2 | 7 | 6.2 | 19 | 15.2 |
| Permian | - | - | 5 | 4.6 | 5 | 5.0 | 9 | 8.2 |
| Hardeman | - | - | - | - | - | - | - | - |
| Total | 1 | 1.0 | 9 | 7.8 | 12 | 11.2 | 28 | 23.4 |
| Wells Brought On-stream | Three Months Ended December 31, 2013 |
Three Months Ended December 31, 2012 |
Year Ended December 31, 2013 |
Year Ended September 30, 2012 |
||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |
| Salt Flat | - | - | 5 | 4.0 | 6 | 5.2 | 19 | 15.2 |
| Permian | - | - | 4 | 3.7 | 6 | 6.0 | 8 | 7.4 |
| Hardeman | - | - | - | - | - | - | - | - |
| Total | - | - | 9 | 7.7 | 12 | 11.2 | 27 | 22.6 |
The Trust's 2013 drilling program was successfully completed in the third quarter of 2013 with the exception of one salt water disposal well drilled in Salt Flat during the fourth quarter.
Capital expenditures
Capital spending during the quarter and year ended December 31, 2013 and December 31, 2012 was as follows:
| Three Months Ended December 31, 2013 |
Three Months Ended December 31, 2012 |
Year Ended December 31, 2013 |
Year Ended December 31, 2012 |
|
| (000's) | $ | $ | $ | $ |
| Exploration and evaluation(1) | - | 120 | 63 | 303 |
| Acquisition of Permian properties- 92.5% interest | - | - | - | 115,902 |
| Acquisition of Permian properties- 7.5 % interest | (62) | - | 8,768 | - |
| Acquisition of Hardeman properties | 27,087 | - | 27,087 | - |
| Intangible drilling and completions | 1,017 | 9,628 | 26,198 | 30,032 |
| Well equipment and facilities | 388 | 1,030 | 3,856 | 12,848 |
| Office furniture and fixtures | 6 | - | 86 | - |
| Proceeds from disposal of assets | (106) | - | (106) | - |
| Other | 12 | 129 | 129 | 274 |
| $ 28,342 | $ 10,907 | $ 66,081 | $ 159,359 |
Note:
(1) Exploration and evaluation expenditures relate to amounts spent on land to which no proven reserves are yet assigned.
During the fourth quarter, capital spending was minimal, with the Trust incurring $1.4 million on drilling, completions, equipment and facilities. Of this total, $0.9 million was for drilling one salt water disposal well and $0.4 million was for well completions on the Salt Flat properties and $0.1 million was for well completions on the Permian properties.
Acquisitions
On April 22, 2013, the Trust acquired the remaining 7.5% interest in its Permian properties for cash consideration of $8.8 million which includes a closing adjustment credit of approximately $0.1 million. The Trust now owns a 100% working interest in its Permian properties. Consideration was comprised of cash. The acquisition has been accounted for as a business combination with the fair value of the net assets as follows:
| $000's | ||
| Identifiable assets acquired and liabilities assumed: | ||
| Oil and gas properties | $ 8,914 | |
| Decommissioning liabilities | (84) | |
| $ 8,830 | ||
On November 25, 2013, Eagle acquired producing properties in Hardeman County, Texas for cash consideration of $27.1 million, which included a preliminary closing adjustment credit of $0.6 million. The seller's working interest production from the properties at the date of acquisition was approximately 300 boe per day, consisting of 97% light sweet crude (43° API) from 34 (29.9 net) producing wells. Through this acquisition, with an effective date of December 1, 2013, Eagle also acquired 7,920 gross (7,395 net) undeveloped acres. Eagle estimated the average annual decline rate of the Hardeman County properties to be 12%. In addition, upon successful closing of this acquisition, Eagle's lenders 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 term credit facility of $US 10.0 million. Eagle used an advance under this credit facility to fund the acquisition. Had this transaction closed on January 1, 2013, the additional revenue, net of royalties would have been approximately $US 5.8 million for the period ended December 31, 2013. The net income effect is not determinable. Consideration was comprised of cash. The acquisition has been accounted for as a business combination with the fair value of the net assets as follows:
| $000's | ||
| Identifiable assets acquired and liabilities assumed: | ||
| Oil and gas properties | $ 27,675 | |
| Decommissioning liabilities | (588) | |
| $ 27,087 | ||
Year-end reserves information
An independent evaluation of the Trust's reserves at December 31, 2013 was conducted by Netherland, Sewell & Associates, Inc. The reserves evaluation report is effective December 31, 2013 and was prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
2013 Year-end reserves report - highlights
- A 14% year-over-year increase in value (PV10) and volume of proved developed producing reserves.
- 77% of the proved developed producing reserves are light oil, 13% are natural gas liquids and 10% are natural gas.
- A 19% year-over-year increase in value (PV10) of total proved reserves and a 3% increase in volumes.
- Closed two acquisitions, adding approximately 2.2 million boe of proved plus probable reserves and 400 boe/d of production at an acquisition cost, including future development costs, of approximately $17.28/boe.
- Total proved plus probable reserves of approximately 14.3 million boe (76% proved, 36% proved producing).
- Proved plus probable reserve life index of 11.7 years based on the mid-point of 2014 average working interest production guidance.
The following tables summarize the independent reserves estimates and values as at December 31, 2013 of Eagle's reserves:
Summary of reserves
| Reserves Category | Company Gross(1)(2) | |||||
| Crude Oil |
Natural Gas Liquids |
Natural Gas |
Total Oil Equivalent 2013 |
Total Oil Equivalent 2012 |
||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | (Mboe) | ||
| Proved | ||||||
| Developed Producing | 3,997 | 686 | 3,035 | 5,189 | 4,558 | |
| Developed Non-Producing | 1,012 | 200 | 830 | 1,350 | 784 | |
| Undeveloped | 3,218 | 689 | 2,855 | 4,383 | 5,270 | |
| Total Proved | 8,226 | 1,576 | 6,720 | 10,922 | 10,612 | |
| Probable | 2,826 | 343 | 1,428 | 3,407 | 5,023 | |
| Total Proved Plus Probable | 11,052 | 1,919 | 8,148 | 14,329 | 15,635 | |
Notes:
(1) Company gross reserves are Eagle's total working interest share before the deduction of any royalties and without including any of Eagle's royalty interests. Eagle holds non-material overriding royalty interests in certain of its assets in the Permian properties.
(2) Totals may not add due to rounding.
Summary of net present value of future net revenue of reserves
| Reserves Category | Net Present Value of Future Net Revenue Before Income Taxes Discounted at (%/year)(1)(2) |
|||||
| 0% | 5% | 10% | 15% | 20% | ||
| ($US 000's) | ($US 000's) | ($US 000's) | ($US 000's) | ($US 000's) | ||
| Proved | ||||||
| Developed Producing | 207,731 | 158,064 | 131,949 | 115,487 | 103,925 | |
| Developed Non-Producing | 41,547 | 31,963 | 25,632 | 21,175 | 17,877 | |
| Undeveloped | 102,916 | 62,620 | 40,879 | 27,963 | 19,703 | |
| Total Proved | 352,194 | 252,646 | 198,459 | 164,626 | 141,505 | |
| Probable | 135,719 | 94,601 | 71,212 | 56,366 | 46,187 | |
| Total Proved Plus Probable | 487,913 | 347,248 | 269,672 | 220,992 | 187,692 | |
Notes:
(1) Estimates of after-tax future net revenue are not presented because it is expected that neither Eagle nor the Trust will be subject to taxes in Canada.
(2) Based on GLJ Petroleum Consultants Ltd.'s January 1, 2014 forecast prices.
(3) 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 news release 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.
At a 10% discount factor, proved producing reserves comprise 49% (2012 - 44%) of the total proved and probable value. Total proved reserves account for 74% (2012 - 63%) of the proved plus probable value.
Capital efficiency table
During 2013, Eagle's capital expenditures, including acquisition capital, resulted in capital efficiency statistics as shown in the following table. Note that statistics which cannot be meaningfully calculated are shown as a dashed line:
| 2013 | 2012 | ||||
| Proved | Proved plus Probable |
Proved | Proved plus Probable |
||
| Exploration and Development expenditures ($000) (1) | 30,226 | 30,226 | 43,183 | 43,183 | |
| Acquisitions ($000) (2) | 35,855 | 35,855 | 115,902 | 115,902 | |
| Change in future development capital ($000) | |||||
| Exploration and development | (18,567) | (17,350) | (16,968) | (32,617) | |
| Acquisitions | 1,228 | 1,308 | 95,113 | 95,113 | |
| Reserves additions (Mboes) | |||||
| Exploration and development | (504) | (2,358) | (230) | (1,319) | |
| Acquisitions | 1,913 | 2,151 | 8,103 | 10,226 | |
| 1,409 | (207) | 7,873 | 8,907 | ||
| Acquisition costs ($/boe) (1) | |||||
| Including change in FDC (3) | 19.38 | 17.28 | 26.04 | 20.63 | |
| Excluding change in FDC | 18.74 | 16.67 | 14.30 | 11.33 | |
| Finding, development & acquisitions costs ($/boe) (1)(4) | |||||
| Including change in FDC (3) | 34.59 | - | 30.13 | 24.88 | |
| Excluding change in FDC | 46.90 | - | 20.20 | 17.86 | |
| Recycle ratio (4) | 1.5x | - | 1.6x | 1.9x | |
| Reserves replacement (5) | 128% | - | 832% | 942% | |
| Reserve life index (yrs) (6) | 8.9 | 11.7 | 9.7 | 14.3 | |
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 costs related to the 2013 asset acquisitions in the Permian and Hardeman properties.
(3) 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.
(4) The recycle ratio is calculated using Eagle's 2013 field netback of $52.23 per boe (2012 - $47.31 per boe) (see the Field Netback section of this MD&A) and dividing that number by the FD&A costs per boe.
(5) The reserves replacement ratios are calculated by dividing average working interest production for the year into total reserve additions.
(6) The 2013 reserve life index calculation is based on the mid-point of Eagle's 2014 average working interest production guidance of 3,350 boe/d and the 2012 reserve life index calculation was based on 3,000 boe/d.
Non-IFRS financial measures
Statements throughout this news release make reference to the terms "field netback" and "funds flow from operations" which are non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are therefore unlikely to 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. See the "Non-IFRS financial measures" section of this news release for a reconciliation of funds flow from operations and field netback to income 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: the Trust's 2014 capital budget and specific uses, including the Trust's 2014 drilling plans; the Trust's expectation regarding its 2014 average working interest production, 2014 operating costs, 2014 field netbacks and 2014 flow from operations; the Trust's expectation that its 2014 capital budget should be sufficient to grow 2014 average working interest production and funds flow by approximately 10% over 2013; the Trust's expectation that its funds flow from operations and undrawn credit facility will be sufficient to fund its current and expected financial obligations; projected payout ratios and the sensitivities of funds flow and payout ratios to changes in production rates and commodity prices; sustainability of production; amount of and sustainability of distributions on the Units; percentage weighting of oil, gas and NGLs in 2014 production; existing credit facilities and the availability of new credit facilities to fund acquisitions; cash available from the distribution reinvestment and Premium Drip™ programs; the taxability of the Trust and the status of the Trust as a mutual fund trust and not a SIFT trust; projected debt to cash flow, and management's objective to maintain a debt to cash flow ratio below 1.5 times; estimated reserve life index; the Trust's expectations regarding the potential of the emerging horizontal well play on the Permian property to add future reserves; 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; 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 not 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; the Trust's 2014 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; unitholder participation in Eagle's Premium Drip™ and distribution reinvestment programs; 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 ("AIF") available on SEDAR at www.sedar.com: volatility of oil, natural gas and NGL 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; 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 Trust's December 31, 2013 AIF under the heading "Risk Factors".
As a result of these risks, actual performance and financial results in 2014 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, 2014 capital budget, estimated 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 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.
Oil and natural gas equivalency measures
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 publicly traded, oil and natural gas focused, reliable distribution paying 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.
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:
Richard W. Clark
President and Chief Executive Officer
(403) 531-1575
rclark@eagleenergytrust.com
Eagle Energy Trust
Kelly Tomyn
Chief Financial Officer
(403) 531-1574
ktomyn@eagleenergytrust.com
www.eagleenergytrust.com