CALGARY, ALBERTA–(Marketwired – March 16, 2017) – Eagle Energy Inc. (TSX:EGL) (“Eagle“) is pleased to report its financial and operating results and its reserves information for the year ended December 31, 2016.
Richard Clark, Chief Executive Officer, commented, “Eagle closed out 2016 with strong reserve metrics, production exceeding the upper end of our guidance range, monthly operating costs at the lower end of our guidance range and ending debt levels as expected. In addition, with our March 13, 2017 announcement of a new four year secured term loan with White Oak Global Advisors, LLC, we have expanded our borrowing capacity by 24% and established a foundation upon which we can execute our new growth strategy over the next four years and accelerate the development of our low risk drilling inventory.”
Eagle’s reserves data and other oil and gas information is included in its Annual Information Form dated March 16, 2017 for the year ended December 31, 2016 (“AIF“). The audited consolidated financial statements, management’s discussion and analysis and AIF have been filed with the securities regulators and are available online under Eagle’s issuer profile on SEDAR at www.sedar.com and on Eagle’s website at www.EagleEnergy.com.
This news release contains non-IFRS financial measures and statements that are forward-looking. Investors should read the sections titled “Non-IFRS Financial Measures” and “Note about Forward-Looking Statements” near the end of this news release. Figures within this news release are presented in Canadian dollars unless otherwise indicated.
Highlights for the Year ended December 31, 2016
Eagle achieved the following results in 2016:
- A total proved reserve replacement ratio of 184% and a total proved plus probable reserve replacement ratio of 272%.
- Total proved plus probable finding, development and acquisition costs (including changes in future development costs) of $7.16 per barrel of oil equivalent (“boe“).
- An 18% year-over-year increase in the net present value of proved plus probable reserves (discounted at 10%), with minimal capital investment and within a lower forward pricing environment.
- Average production increased by 18% year-over-year to 3,972 barrels of oil equivalent per day (“boe/d“) (84% oil, 3% natural gas liquids (“NGLs“) and 13% natural gas).
- A 12% year-over-year reduction in per boe operating costs (inclusive of transportation).
- Funds flow from operations of $15.8 million ($10.87 per boe or $0.38 per share) and ending net debt of $59 million.
On March 13, 2017, Eagle announced an increase to its borrowing capacity by way of a new four year secured term loan and its 2017 capital budget, production and operating cost guidance. In addition, as Eagle embarks on a more growth-oriented strategy, it announced a suspension of its dividend following the payment of its February dividend. The February dividend of $0.005 per common share that was previously declared on February 15, 2017 for shareholders of record on February 28, 2017 will still be paid on March 23, 2017.
Term Loan Financing – $CA 87 million ($US 65 million) – closed March 13, 2017
- Eagle has expanded its borrowing capacity by 24% to approximately $87 million ($US 65 million), which establishes a foundation for Eagle to execute its new growth strategy over the next four years and accelerate the development of its low risk drilling inventory.
- Eagle has replaced its entire $70 million authorized bank credit facility with a new four year secured term loan from White Oak Global Advisors, LLC (“White Oak“) which provides up to $87 million (the current Canadian dollar equivalent of $US 65 million) of financing. Headquartered in San Francisco, White Oak is an SEC-registered investment adviser with assets under management of approximately $US 3 billion and affords Eagle a partner that has the capacity to provide additional financing to fund future acquisitions.
- At closing, Eagle drew approximately $82 million (the current Canadian dollar equivalent of $US 61.5 million) and can draw the remaining $US 3.5 million prior to the first anniversary of closing.
- Based on Eagle’s 2016 ending net debt of $59 million and execution of its approved 2017 budget, Eagle expects 2017 ending net debt to be $71.2 million, thus affording Eagle approximately $13 million in combined working capital and undrawn term loan availability at the end of 2017 (see “2017 Outlook”).
- Eagle’s expanded credit base, coupled with its 2017 expected funds flow from operations (see “2017 Outlook”) has allowed a four-fold increase in the capital budget from 2016. Expected growth in year-over-year fourth quarter average production is 8%, but more impactful will be the exploitation of substantial, internally-identified drilling opportunities in Eagle’s Hardeman and Twining fields that the 2017 capital budget is expected to provide.
Highlights of 2017 Budget
On March 13, 2017, Eagle announced its 2017 budget, with the following highlights:
- 2017 capital budget of $22.8 million ($US 12.5 million for its operations in the United States and $6.6 million for its operations in Canada). Included in the $US 12.5 million capital budget is $US 3.5 million for land acquisitions on seismically-defined play trends in Eagle’s Hardeman area, which will provide a platform for economic production growth in future years.
- 2017 production guidance of 3,800 to 4,000 boe/d (including working interest and royalty interest volumes), resulting in 8% year-over-year fourth quarter production growth. Eagle’s proved developed producing corporate decline rate is approximately 18% per annum.
- 2017 field netbacks of $25.78 / boe (based on the assumptions as set out below under the heading “2017 Outlook”).
- 2017 monthly operating cost guidance (inclusive of transportation) of $2.1 million to $2.3 million per month, resulting in per boe operating costs of $19.04 (figure based on the mid-range guidance level of $2.2 million per month).
- 2017 funds flow from operations of $16.0 million ($0.38 per share), consistent with 2016 levels and incorporating a 16% forecast decrease year-over-year of general and administrative expenses.
- 2017 ending net debt of $71.2 million, affording Eagle approximately $13 million in combined working capital and undrawn term loan availability at the end of 2017 (based on the assumptions as set out below under the heading “2017 Outlook”).
2017 Outlook
This outlook section is intended to provide shareholders with information about Eagle’s expectations for capital expenditures, production and operating costs for 2017. 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.
Eagle’s 2017 guidance for its capital budget, average production and monthly operating costs together with resulting funds flow from operations, ending net debt and field netback (excluding hedges) (based on management’s assumptions) remains unchanged from what Eagle previously announced on March 13, 2017 and is as follows:
| 2017 Guidance | Notes | |||
| Capital Budget | $22.8 mm | (1) | ||
| Average Production | 3,800 to 4,000 boe/d | (2) | ||
| Operating Expenses per month | $2.1 to $2.3 mm | (3) | ||
| Funds Flow from Operations | $16.0 mm | (4) | ||
| Ending Net Debt | $71.2 mm | |||
| Field Netback (excluding hedges) | $25.78 / boe | (5) |
Notes:
| (1) | The 2017 capital budget of $22.8 million consists of $US 12.5 million for Eagle’s operations in the United States and $6.6 million for Eagle’s operations in Canada. | |||
| (2) | 2017 production is forecast to consist of 84% oil, 3% NGLs and 13% natural gas. These numbers include working interest and royalty interest volumes. | |||
| (3) | Operating expense guidance is stated on a per month basis rather than per boe basis due to the mostly fixed nature of the costs. | |||
| (4) | 2017 funds flow from operations is expected to be approximately $16.0 million based on the following assumptions: | |||
| (a) | average production of 3,900 boe/d (the mid-point of the guidance range); | |||
| (b) | pricing at $US 55.46 per barrel WTI oil, $US 3.36 per Mcf NYMEX gas, $CA 2.79 per Mcf AECO and $US 19.41 per barrel of NGL (NGL price is calculated as 35% of the WTI price); | |||
| (c) | differential to WTI is $US 3.18 discount per barrel in Salt Flat, $US 3.50 discount per barrel in Hardeman, $CA 11.50 discount per barrel in Dixonville and $CA 8.00 discount per barrel in Twining; | |||
| (d) | average operating costs of $2.2 million per month ($US 0.8 million per month for Eagle’s operations in the United States and $1.2 million per month for Eagle’s operations in Canada), the mid-point of the guidance range; and | |||
| (e) | a foreign exchange rate of $US 1.00 equal to $CA 1.30. | |||
| (5) | This figure assumes average operating costs of $2.2 million per month (the mid-point of the guidance range) and a $US 55.46 WTI price. Field netback is a non-IFRS financial measure. Refer to the section below titled “Non-IFRS Financial Measures”. | |||
Tables showing the sensitivity of Eagle’s 2017 funds flow from operations to changes in commodity prices, production and foreign exchange rates are set out below under “2017 Sensitivities”.
2017 Sensitivities
The following tables show the sensitivity of Eagle’s 2017 funds flow from operations to changes in commodity prices, production and foreign exchange (“FX“) rates:
| Funds Flow from Operations | 2017 Average Production (3,900 boe/d) | |||||
| Sensitivity to Commodity Price | FX 1.25 | FX 1.30 | FX 1.35 | |||
| $US 45.00 WTI | $13.7 mm | $14.9 mm | $16.0 mm | |||
| $US 55.00 WTI | $14.9 mm | $16.0 mm | $17.2 mm | |||
| $US 65.00 WTI | $15.0 mm | $16.1 mm | $17.4 mm | |||
| Sensitivity to Production | 2017 Average Production (3,900 boe/d) (WTI $US 55.00, FX 1.30) |
|||||
| 3,800 | 3,900 | 4,000 | ||||
| Funds Flow from Operations ($CA) | $15.1 mm | $16.0 mm | $17.0 mm | |||
Assumptions:
| (1) | Operating costs are assumed to be $2.2 million per month (mid-point of guidance range). | |
| (2) | Differential to WTI is held constant. | |
| (3) | The foreign exchange rate is assumed to be $US 1.00 equal to $CA 1.30, unless otherwise indicated in the table. |
Updated Dividend Strategy
Concurrent with embarking on a more growth oriented strategy, on March 13, 2017, Eagle announced the suspension of its dividend following the payment of its February dividend. The February dividend of $0.005 per common share of Eagle that was previously declared on February 15, 2017 for shareholders of record on February 28, 2017 will still be paid on March 23, 2017.
Previously, Eagle focused on a sustainable business model with capital expenditures using less than 100% of its annual cash flow to deliver total returns to its shareholders through both dividends and modest production growth. However, Eagle’s capital budget for 2017, a year in which Eagle plans to build the platform for future reserves and production growth, requires 145% of Eagle’s 2017 expected cash flow. This decision makes the payment of a dividend neither sustainable nor sensible. When Eagle has successfully implemented this capital intensive phase of its growth, the Board may consider reinstating an appropriate dividend.
Year-end Reserves Information
An independent evaluation of Eagle’s U.S. reserves was conducted by Netherland, Sewell & Associates, Inc. and of Eagle’s Canadian reserves by McDaniel & Associates Consultants Ltd. These reserves evaluation reports are effective December 31, 2016 and were prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Details regarding Eagle’s reserves and oil and gas assets are set forth in Eagle’s AIF.
2016 Year-End Reserves Report – Highlights
- Increased year-over-year proved developed producing reserves by 2%, total proved reserves by 9% and total proved plus probable reserves by 13%.
- Grew total proved plus probable reserves to approximately 20.9 million boe (68% proved, 52% proved producing).
- 92% of the proved developed producing reserves are light oil.
- Achieved total proved plus probable finding, development and acquisition costs (including changes in future development costs) of $7.16 per boe.
- Maintained Eagle’s proved plus probable reserve life index above 14 years and replaced 184% of its reserves on a proved basis.
The following tables summarize the independent reserves estimates and values of Eagle’s reserves as at December 31, 2016:
Summary of Reserves
| Canadian Operations | Company Gross(1) | ||||||||||
| Reserves Categories | Crude Oil | Natural Gas Liquids | Natural Gas | Total Oil Equivalent 2016 | Total Oil Equivalent 2015 | ||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | (Mboe) | |||||||
| Proved | |||||||||||
| Developed producing | 7,258 | 108 | 3,666 | 7,976 | 8,247 | ||||||
| Developed non-producing | 61 | 15 | 449 | 150 | 139 | ||||||
| Undeveloped | 833 | 58 | 1,765 | 1,185 | 787 | ||||||
| Total proved | 8,152 | 180 | 5,880 | 9,311 | 9,173 | ||||||
| Total probable | 3,856 | 118 | 3,774 | 4,602 | 4,174 | ||||||
| Total proved plus probable | 12,007 | 297 | 9,653 | 13,914 | 13,347 | ||||||
| US Operations | Company Gross(1) | ||||||||||
| Reserves Categories | Crude Oil | Natural Gas Liquids | Natural Gas | Total Oil Equivalent 2016 | Total Oil Equivalent 2015 | ||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | (Mboe) | |||||||
| Proved | |||||||||||
| Developed producing | 2,851 | 53 | 329 | 2,959 | 2,501 | ||||||
| Developed non-producing | 400 | 16 | 79 | 429 | 348 | ||||||
| Undeveloped | 1,339 | 75 | 371 | 1,475 | 1,007 | ||||||
| Total proved | 4,590 | 144 | 778 | 4,864 | 3,856 | ||||||
| Total probable | 1,905 | 125 | 618 | 2,132 | 1,358 | ||||||
| Total proved plus probable | 6,494 | 269 | 1,396 | 6,996 | 5,214 | ||||||
| Total Company Operations | Company Gross(1) | ||||||||||
| Reserves Categories | Crude Oil | Natural Gas Liquids | Natural Gas | Total Oil Equivalent 2016 | Total Oil Equivalent 2015 | ||||||
| (Mbbls) | (Mbbls) | (MMcf) | (Mboe) | (Mboe) | |||||||
| Proved | |||||||||||
| Developed producing | 10,109 | 161 | 3,994 | 10,935 | 10,748 | ||||||
| Developed non-producing | 461 | 31 | 528 | 579 | 487 | ||||||
| Undeveloped | 2,172 | 133 | 2,136 | 2,660 | 1,793 | ||||||
| Total proved | 12,741 | 324 | 6,658 | 14,175 | 13,028 | ||||||
| Total probable | 5,760 | 242 | 4,392 | 6,735 | 5,533 | ||||||
| Total proved plus probable | 18,502 | 567 | 11,050 | 20,910 | 18,561 | ||||||
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
| Canadian Operations | Net Present Value of Future Net Revenue Before Income Taxes Discounted at (%/year) |
||||||||||
| Reserves Category | 0% | 5% | 10% | 15% | 20% | ||||||
| $CA | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ||||||
| Proved | |||||||||||
| Developed producing | 203,164 | 129,239 | 92,883 | 72,510 | 59,796 | ||||||
| Developed non-producing | 2,471 | 1,937 | 1,490 | 1,159 | 919 | ||||||
| Undeveloped | 20,770 | 13,252 | 8,659 | 5,678 | 3,638 | ||||||
| Total proved | 226,405 | 144,428 | 103,032 | 79,347 | 64,353 | ||||||
| Total probable | 152,563 | 65,425 | 36,994 | 24,688 | 18,114 | ||||||
| Total proved plus probable | 378,969 | 209,854 | 140,026 | 104,035 | 82,467 | ||||||
| US Operations | Net Present Value of Future Net Revenue Before Income Taxes Discounted at (%/year) |
||||||||||
| Reserves Category | 0% | 5% | 10% | 15% | 20% | ||||||
| $US | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ||||||
| Proved | |||||||||||
| Developed producing | 82,388 | 59,325 | 47,900 | 40,847 | 35,950 | ||||||
| Developed non-producing | 18,748 | 9,994 | 6,915 | 5,440 | 4,558 | ||||||
| Undeveloped | 30,666 | 22,750 | 17,187 | 13,129 | 10,083 | ||||||
| Total proved | 131,803 | 92,069 | 72,002 | 59,416 | 50,591 | ||||||
| Total probable | 68,170 | 46,992 | 34,551 | 26,620 | 21,260 | ||||||
| Total proved plus probable | 199,972 | 139,061 | 106,553 | 86,036 | 71,851 | ||||||
| Total Company Operations | Net Present Value of Future Net Revenue Before Income Taxes Discounted at (%/year) |
||||||||||
| Reserves Category | 0% | 5% | 10% | 15% | 20% | ||||||
| $CA | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ($000’s) | ||||||
| Proved | |||||||||||
| Developed producing | 303,952 | 202,673 | 152,684 | 123,845 | 105,222 | ||||||
| Developed non-producing | 24,961 | 14,095 | 9,997 | 7,905 | 6,607 | ||||||
| Undeveloped | 56,761 | 39,851 | 28,648 | 20,840 | 15,172 | ||||||
| Total proved | 385,674 | 256,619 | 191,329 | 152,591 | 127,000 | ||||||
| Total probable | 234,039 | 121,874 | 78,711 | 56,991 | 44,041 | ||||||
| Total proved plus probable | 619,714 | 378,493 | 270,039 | 209,852 | 171,041 | ||||||
Notes:
| (1) | It should not be assumed that the net present values of estimated future net revenue shown above are representative of the fair market value of the reserves. There is no assurance that the underlying 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. | |
| (2) | The U.S. operations numbers have been converted into Canadian dollars using the following foreign exchange rates: 2017 – $CA 1.00 equal to $US 0.750; 2018 – $CA 1.00 equal to $US 0.775; 2019 – $CA 1.00 equal to $US 0.800; 2020 – $CA 1.00 equal to $US 0.825; 2021 and thereafter – $CA 1.00 equal to $US 0.850 (as per McDaniel & Associates Consultants Ltd. January 1, 2017 price deck forecast). | |
| (3) | Totals may not add due to rounding. |
At a 10% discount factor, proved developed producing reserves comprise 57% (2015 – 61%) of the total proved plus probable value. Total proved reserves account for 71% (2015 – 75%) of the total proved plus probable value.
Future Development Costs (“FDC”)
Total future development costs are estimated at $41.7 million for total proved and $62.3 million for total proved plus probable reserves. When compared to 2017 funds flow from operations guidance of $16.0 million (see the “2017 Outlook” section of this news release for assumptions), future development costs represent 2.6 years and 3.9 years of funds flow from operations, respectively.
Reserves Performance Ratios
During 2016, Eagle’s capital expenditures, including acquisition capital, resulted in capital efficiency statistics as shown in the following table.
| 2016 | 2015 | ||||||||
| Proved | Proved plus Probable |
Proved | Proved plus Probable |
||||||
| Reserves (Mboe) | 14,175 | 20,910 | 13,028 | 18,561 | |||||
| Capital Expenditures ($M) | |||||||||
| Exploration and Development (“E&D“)(1)(8) | 5,771 | 5,771 | 14,134 | 14,134 | |||||
| Acquisition(2)(8) | 5,144 | 5,144 | 30,970 | 30,970 | |||||
| Total Capital Expenditures | 10,915 | 10,915 | 45,104 | 45,104 | |||||
| Field Netbacks ($/boe)(3) | |||||||||
| Current Year | 16.12 | 16.12 | 19.30 | 19.30 | |||||
| Finding, Development and Acquisition (“FD&A”) Costs(4)(8) | |||||||||
| Change in Future Development Costs (“FDC“) ($M) | 11,219 | 15,691 | 8,652 | 8,006 | |||||
| Reserve Additions (Mboes) | 2,515 | 3,717 | 2,880 | 3,788 | |||||
| FD&A Costs including changes in FDC ($/boe)(4) | 8.80 | 7.16 | 18.66 | 14.02 | |||||
| FD&A Costs excluding changes in FDC ($/boe)(4) | 4.34 | 2.94 | 15.66 | 11.91 | |||||
| Recycle Ratio(5)(8) | 1.83 | 2.25 | 1.03 | 1.38 | |||||
| Reserves Replacement(6)(8) | 184% | 272% | 234% | 307% | |||||
| Reserves Life Index (yrs)(7)(8) | 10.4 | 15.3 | 10.4 | 14.9 | |||||
Notes:
| (1) | E&D is equal to expenditures for “exploration and evaluation” plus “oil and gas properties” from the Consolidated Cash Flow Statement. | |
| (2) | Acquisition refers to the January 2016 acquisition of Maple Leaf Royalties Corporation and the 2015 acquisition of the Twining properties. See note 6 of the Audited Consolidated Annual Financial Statements. | |
| (3) | Field netbacks are calculated by subtracting royalties, operating expenses, and transportation and marketing expenses from revenues, which are from the Consolidated Statement of Earnings (Loss) and Comprehensive Earnings (Loss). Field netback is a non-IFRS financial measure. See “Non-IFRS Financial Measures”. | |
| (4) | Eagle calculates FD&A costs incorporating both the costs and associated reserve additions related to E&D and acquisitions during the year. Eagle believes that FD&A costs provide useful information to investors because it is a measure of the cost to locate new reserves and the ongoing expense of extracting petroleum throughout the lifecycle of the reserves. | |
| (5) | Recycle ratio is calculated by dividing field netback per boe by FD&A costs including changes in FDC per boe. Eagle believes that the recycle ratio provides useful information to investors because it is a measure of a company’s production efficiency based on its FD&A costs. | |
| (6) | Reserves Replacement is calculated by dividing reserve additions by total working interest production for the year, which, in 2016, is based on average working interest production of 3,740 boe/d (2015 – 3,358 boe/d). | |
| (7) | Reserves Life Index is calculated by dividing reserves by total working interest production for the year, which, in 2016, is based on average working interest production of 3,740 boe/d (2015 – 3,358 boe/d). | |
| (8) | Eagle cautions readers as to the reliability of these capital efficiency statistics as these measures do not have any standardized meaning and may not be comparable to similar measures presented by other issuers. |
Selected Annual Information
The following table shows selected information for Eagle’s fiscal years ended December 31, 2016, December 31, 2015 and December 31, 2014.
| Years ended December 31 | 2016 | 2015 | 2014 | ||||||
| ($000’s except per share amounts and production) | |||||||||
| Sales volumes – boe/d | 3,972 | 3,358 | 2,782 | ||||||
| Revenue, net of royalties | 48,993 | 48,121 | 67,175 | ||||||
| Field netback | 23,437 | 23,659 | 50,522 | ||||||
| Funds flow from operations | 15,798 | 30,738 | 33,958 | ||||||
| per share – basic | 0.38 | 0.88 | 1.01 | ||||||
| per share – diluted | 0.38 | 0.88 | 1.00 | ||||||
| Earnings (loss) | 9,559 | (76,046 | ) | (48,028 | ) | ||||
| per share – basic | 0.23 | (2.18 | ) | (1.43 | ) | ||||
| per share – diluted | 0.23 | (2.18 | ) | (1.55 | ) | ||||
| Current assets | 9,302 | 19,767 | 33,245 | ||||||
| Current liabilities | 74,758 | 9,397 | 10,720 | ||||||
| Total assets | 218,199 | 208,572 | 257,172 | ||||||
| Total non-current liabilities | 26,202 | 92,616 | 57,547 | ||||||
| Shareholders’ equity | 117,239 | 106,559 | 188,905 | ||||||
| Dividends declared | 3,821 | 12,040 | 33,524 | ||||||
| per issued share | 0.09 | 0.35 | 0.99 | ||||||
| Shares issued | 42,452 | 34,863 | 35,017 | ||||||
Summary of Quarterly Results
| Q4/2016 | Q3/2016 | Q2/2016 | Q1/2016 | Q4/2015 | Q3/2015 | Q2/2015 | Q1/2015 | |||||||||||||||
| ($000’s except for boe/d and per share amounts) | ||||||||||||||||||||||
| Sales volumes – boe/d | 3,803 | 4,085 | 4,147 | 3,854 | 3,783 | 3,607 | 3,034 | 2,995 | ||||||||||||||
| Revenue, net of royalties | 13,891 | 12,854 | 13,149 | 9,099 | 11,603 | 13,428 | 12,884 | 10,206 | ||||||||||||||
| per boe | 39.72 | 34.20 | 34.84 | 25.94 | 33.34 | 40.46 | 46.66 | 37.86 | ||||||||||||||
| Operating expenses | 6,799 | 6,564 | 5,928 | 6,265 | 6,356 | 6,473 | 5,171 | 5,978 | ||||||||||||||
| per boe | 19.44 | 17.46 | 15.71 | 17.86 | 18.26 | 19.50 | 18.73 | 22.18 | ||||||||||||||
| Field netback | 7,092 | 6,290 | 7,221 | 2,834 | 5,246 | 6,956 | 7,713 | 3,744 | ||||||||||||||
| per boe | 20.28 | 16.74 | 19.13 | 8.08 | 15.08 | 20.96 | 27.94 | 13.89 | ||||||||||||||
| Funds flow from operations | 3,901 | 4,582 | 5,148 | 2,167 | 5,147 | 7,332 | 10,532 | 7,727 | ||||||||||||||
| per boe | 11.15 | 12.19 | 13.64 | 6.18 | 14.79 | 22.09 | 38.14 | 28.67 | ||||||||||||||
| per share – basic | 0.09 | 0.11 | 0.12 | 0.05 | 0.15 | 0.21 | 0.30 | 0.22 | ||||||||||||||
| per share – diluted | 0.09 | 0.11 | 0.12 | 0.05 | 0.15 | 0.21 | 0.30 | 0.22 | ||||||||||||||
| Earnings (loss) | 30,508 | 52 | (9,288 | ) | (11,713 | ) | (23,198 | ) | (51,784 | ) | (6,541 | ) | 5,477 | |||||||||
| per share – basic | 0.72 | 0.00 | (0.23 | ) | (0.29 | ) | (0.67 | ) | (1.48 | ) | (0.19 | ) | 0.16 | |||||||||
| per share – diluted | 0.72 | 0.00 | (0.23 | ) | (0.29 | ) | (0.67 | ) | (1.48 | ) | (0.19 | ) | 0.16 | |||||||||
| Cash dividends paid | 637 | 636 | 1,274 | 1,584 | 2,614 | 3,143 | 3,130 | 3,153 | ||||||||||||||
| per issued share | 0.015 | 0.015 | 0.03 | 0.04 | 0.07 | 0.09 | 0.09 | 0.09 | ||||||||||||||
| Current assets | 9,302 | 9,787 | 10,618 | 12,829 | 19,767 | 21,862 | 13,382 | 31,459 | ||||||||||||||
| Current liabilities | 74,758 | 72,387 | 75,035 | 5,472 | 9,397 | 8,033 | 7,754 | 8,642 | ||||||||||||||
| Total assets | 218,199 | 190,945 | 195,044 | 199,708 | 208,572 | 228,959 | 245,009 | 265,342 | ||||||||||||||
| Total non-current liabilities | 26,202 | 31,690 | 32,397 | 96,317 | 92,616 | 91,316 | 52,012 | 60,835 | ||||||||||||||
| Shareholders’ equity | 117,239 | 86,868 | 87,612 | 97,919 | 106,559 | 129,611 | 185,243 | 195,865 | ||||||||||||||
| Shares issued | 42,452 | 42,452 | 42,452 | 42,452 | 34,863 | 34,893 | 34,961 | 35,023 | ||||||||||||||
During the third quarter of 2016, sales volumes included initial production from wells in Canada and the U.S. that were restarted. The production levelled off during the three months ended December 31, 2016, causing a decrease in sales volumes when compared to the previous quarter.
Despite a quarter-over-quarter decrease in production, field netback increased in the fourth quarter primarily due to higher commodity prices. Funds flow from operations decreased in the fourth quarter of 2016 due to decreased production, increased administrative expenses related to year end costs including audit and reserves and a lower risk management gain due to the higher WTI price. Generally, in times of increasing prices, funds flow from operations increases faster than increases in sales volumes because certain expenses tend to be more fixed in nature, such as general and administrative expenses, and do not change with sales volumes.
Earnings (loss) on a quarterly basis often do 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 earnings (loss), and those that are required to be fair valued at each quarter end. In the fourth quarter of 2016, Eagle recognized an impairment recovery, net of impairment charges, of approximately $34 million.
Advisories
Non-IFRS Financial Measures
Statements throughout this news release make reference to the term “field netback”.
“Field netback” is calculated by subtracting royalties, operating expenses, and transportation and marketing expenses from revenues. This method of calculating field netback is in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). Management believes that field netback provides useful information to investors and management because such a measure reflects the quality of production and the level of profitability.
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. Eagle cautions investors that important factors could cause Eagle’s actual results to differ materially from those projected, or set out, in any forward-looking statements included in this news release.
In particular, and without limitation, this news release contains forward-looking statements pertaining to the following:
- Eagle’s loan with White Oak, including terms relating to future drawings;
- Eagle’s expectations regarding its business strategy and that the loan from White Oak establishes a foundation for Eagle to execute a growth strategy over the next four years and accelerate the development of its low risk drilling inventory;
- Eagle’s expectation that 2017 ending net debt will be $71.2 million, thus affording Eagle approximately $13 million in combined working capital and undrawn term loan availability at the end of 2017;
- Eagle’s estimated volumes and values of reserves;
- Future development costs associated with reserves;
- Eagle’s 2017 capital budgets, specific uses and relationship to 2017 expected cash flow;
- Eagle’s expectations regarding its 2017 full year average production, monthly operating costs, field netbacks (excluding hedges) and proved developed producing corporate decline rate;
- Eagle’s expectation that year-over-year fourth quarter average production will increase and that its 2017 capital budget will enable it to exploit substantial, internally-identified drilling opportunities in Eagle’s Hardeman and Twining fields;
- Eagle’s expectations regarding its 2017 funds flow from operations and sensitivity of this metric to commodity prices, production and foreign exchange rates;
- Eagle’s expectations regarding the reduction in 2017 general and administrative expenses;
- Anticipated crude oil, natural gas liquids and natural gas production weighting; and
- Eagle’s expectations regarding its dividend strategy.
With respect to forward-looking statements contained in this news release, assumptions have been made regarding, among other things:
- future crude oil, NGL and natural gas prices, differentials and weighting;
- future foreign exchange rates;
- future production levels;
- future recoverability of reserves and the accuracy of Eagle’s reserves volumes and values;
- future dividend levels;
- future capital expenditures and the ability of Eagle to obtain financing on acceptable terms for its capital projects, operations and future acquisitions;
- Eagle’s 2017 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 Eagle to complete new acquisitions;
- future production estimates, which are 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, among other things; and
- projected operating costs, which are based on historical information and anticipated changes of the cost of equipment and services, among other things.
Eagle’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and those in the AIF:
- volatility of crude oil, NGL, and natural gas prices;
- commodity supply and demand;
- fluctuations in foreign exchange 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 Eagle and the operations of its subsidiaries.
Additional risks and uncertainties affecting Eagle are contained in the AIF under the heading “Risk Factors”.
As a result of these risks, actual performance and financial results in 2017 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, field netbacks, drilling program, 2017 capital budget, funds flow from operations and reserves 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 Eagle’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 Eagle and its shareholders. These statements speak only as of the date of this news release and may not be appropriate for other purposes. Eagle 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 Inc.
Eagle is an oil and gas corporation with shares listed for trading on the Toronto Stock Exchange under the symbol “EGL”.
All material information about Eagle may be found on its website at www.EagleEnergy.com or under Eagle’s issuer profile at www.sedar.com.
Chief Financial Officer
(403) 531-1574
[email protected]
Richard W. Clark
Chief Executive Officer
(403) 531-1575
[email protected]
Eagle Energy Inc.
Suite 2710, 500-4th Avenue SW
Calgary, Alberta T2P 2V6
(403) 531-1575
(855) 531-1575 (toll free)
[email protected]
