Solid fourth quarter operating results set the stage for a strong 2014
CALGARY, Feb. 6, 2014 /CNW/ – MEG Energy Corp. today reported fourth quarter and full-year 2013 operational and financial results. Highlights include:
“The use of proven technologies was a key component to our performance in 2013 and will remain the central focus of our future plans. The success of MEG’s RISER initiative, coupled with the strong start-up performance of Christina Lake Phase 2B in the fourth quarter, were the main contributors to our solid production results in 2013,” said Bill McCaffrey, MEG President and Chief Executive Officer. “Exit rates were about 13 per cent above the high end of our expectations, which provides a strong foundation for a very exciting year in 2014 as we ramp-up toward our near-term target of 80,000 barrels per day by 2015.”
Exit rate production for the month of December averaged 48,557 bpd. Annual production for 2013 averaged 35,317 bpd, an increase of 23% over 2012 volumes of 28,773 bpd, marking MEG’s fifth consecutive year of annual production gains. Production for the fourth quarter of 2013 increased to a record 42,251 bpd from fourth quarter 2012 production of 32,292 bpd.
Average non-energy operating costs for 2013, at $9.00 per barrel, were at the low end of MEG’s targeted range of $9 to $11 per barrel, an improvement of 7% from 2012 averages. Net operating costs (including energy costs and revenue from electricity sales) for 2013 averaged $10.01 per barrel, consistent with 2012 full-year results and maintaining MEG’s low operating cost position. Net operating costs for the fourth quarter of 2013 were $11.22 per barrel compared to fourth quarter 2012 results of $8.95 per barrel. The difference in fourth quarter net operating costs reflects the benefit of lower non-energy operating costs, offset by higher natural gas energy costs and lower realized prices for electricity sales.
Concurrent with the ramp-up of production in the fourth quarter, MEG commissioned its proprietary 900,000 barrel Stonefell storage terminal and completed its proprietary pipeline connection to the Canexus rail-loading facility at Bruderheim, establishing the first direct well-head to rail pipeline connection in the Canadian oil industry. The first unit-train of MEG product was loaded in December with additional unit-trains loaded in January.
“The strategic advantage of having storage capability at the Stonefell Terminal was demonstrated in the fourth quarter,” said McCaffrey. “With the Alberta oil industry subject to unscheduled pipeline apportionment, we were able to continue producing at maximum rates while positioning ourselves to take greater control of which markets our barrels are sold into, and the timing for the sale of those barrels.”
While fourth quarter 2013 production levels were up 31% from the same period in 2012, sales volumes increased 10% due to approximately 6,300 bpd of production being placed in storage, used as line-fill or capitalized in association with the commissioning of Phase 2B.
Fourth quarter 2013 cash flow from operations was $22.6 million ($0.10 per share, diluted) compared to cash flow from operations of $56.1 million ($0.27 per share, diluted) in the fourth quarter of 2012. Cash flow for the fourth quarter of 2013 was impacted by production volumes that were not sold in the quarter (as noted above), as well as wider light-heavy oil differentials and an increase in diluent costs compared to the same period in 2012.
MEG recognized a net loss for the fourth quarter of 2013 of $148.2 million compared to a net loss of $18.7 million for the fourth quarter of 2012. The loss is primarily due to the unrealized foreign exchange loss on conversion of the company’s U.S. dollar denominated debt as a result of the strengthening of the U.S. dollar against the Canadian dollar.
Capital and Growth Strategy
MEG’s capital program in 2013 was approximately $2.1 billion. Investment was primarily focused on completion of Christina Lake Phase 2B, continued application of RISER at Christina Lake Phases 1 and 2, early work on RISER 2B, and infrastructure to support MEG’s future growth and marketing strategies.
“We’ve already put the capital in place to reach our target of 80,000 barrels per day by 2015,” said McCaffrey. “The investment focus in 2014 is on our next stage of growth through the RISER 2B initiative. The expansion of our existing assets through this brownfield approach will significantly lower the capital intensity of new production and accelerate our cash flows compared to a typical greenfield expansion.”
MEG ended the year with net debt of $2.9 billion, including $1.2 billion in cash and cash equivalents. MEG’s capital resources also include an undrawn US$2.0 billion revolving credit facility.
Reserves Update
GLJ Petroleum Consultants Ltd. (GLJ), an independent reservoir engineering firm, completed an evaluation of MEG’s bitumen reserves and resources effective as of December 31, 2013. Proved bitumen reserves increased by 13% to an estimated 1.4 billion barrels from the previous year. Proved plus probable reserves increased to 2.9 billion barrels from 2.6 billion barrels reflecting higher expected recovery factors and further resource delineation. GLJ’s estimate of contingent resources (on a best estimate basis) was approximately 3.7 billion barrels, compared to 3.4 billion barrels a year earlier.
The pre-tax net present value of the future net cash flows of the proved reserves and of the proved plus probable reserves, discounted at 10% per annum, were $13.5 billion and $21.0 billion, respectively. A summary of GLJ’s report, along with important information regarding net present value calculations and the classification of reserves and contingent resources is included in MEG’s Fourth Quarter 2013 Report to Shareholders.
Operational and Financial Highlights
| Three months ended December 31 | Year ended December 31 | |||
| 2013 | 2012 | 2013 | 2012 | |
| Bitumen production – bpd | 42,251 | 32,292 | 35,317 | 28,773 |
| Bitumen sales – bpd | 35,990 | 32,722 | 33,715 | 28,845 |
| Steam-oil ratio (SOR) | 2.9 | 2.4 | 2.6 | 2.4 |
| West Texas Intermediate (WTI) US$/bbl |
97.43 | 88.18 | 97.96 | 94.21 |
| Differential – Blend vs WTI – % | 40.6% | 29.9% | 32.7% | 31.2% |
| Bitumen realization – $/bbl | 38.22 | 45.67 | 49.28 | 46.93 |
| Net operating costs(1) – $/bbl | 11.22 | 8.95 | 10.01 | 9.98 |
| Non-energy operating costs – $/bbl | 8.09 | 8.70 | 9.00 | 9.71 |
| Cash operating netback(2) – $/bbl | 23.78 | 34.44 | 35.87 | 34.18 |
| Total cash capital investment(3) – $000 | 389,232 | 494,916 | 2,188,353 | 1,598,514 |
| Net income (loss) – $000 | (148,182) | (18,740) | (166,405) | 52,569 |
| Per share, diluted | (0.67) | (0.09) | (0.75) | 0.26 |
| Operating earnings (loss) – $000(4) | (32,685) | (538) | 386 | 21,242 |
| Per share, diluted(4) | (0.15) | (0.00) | 0.00 | 0.11 |
| Cash flow from operations – $000(4) | 22,648 | 56,106 | 253,424 | 212,514 |
| Per share, diluted(4) | 0.10 | 0.27 | 1.13 | 1.06 |
| Cash, cash equivalents and short-term investments – $000 | 1,179,072 | 2,007,841 | 1,179,072 | 2,007,841 |
| Long-term debt – $000 | 4,004,575 | 2,488,609 | 4,004,575 | 2,488,609 |
| Bitumen Reserves and Contingent Resources (millions of barrels, before royalties) | ||||
| Bitumen Reserves (millions of barrels, before royalties) | ||||
| Proved (1P) Reserves(5) | 1,446 | 1,284 | ||
| Probable Reserves(6) | 1,451 | 1,360 | ||
| Proved Plus Probable (2P) Reserves(5)(6) | 2,897 | 2,644 | ||
| Bitumen Contingent Resources (millions of barrels, before royalties) | ||||
| Best Estimate Contingent Resources (2C)(7)(8)(9) | 3,653 | 3,420 | ||
| (1) | Net operating costs include energy and non-energy operating costs, reduced by power sales. |
| (2) | Cash operating netbacks are calculated by deducting the related diluent, transportation, field operating costs and royalties from proprietary sales volumes and power revenues, on a per barrel basis. |
| (3) | Includes capitalized interest of $22.9 million and $76.5 million for the three months and year ended December 31, 2013 respectively ($10.4 million and $30.6 million for the three months and year ended December 31, 2012). |
| (4) | Please refer to Non-IFRS Financial Measures below. |
| (5) | “Proved Reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Proved Reserves are also referred to as “1P Reserves”. |
| (6) | “Probable Reserves” are those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Proved plus probable reserves are also referred to as “2P Reserves”. |
| (7) | “Contingent Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies include further reservoir delineation, additional facility and reservoir design work, submission of regulatory applications and the receipt of corporate approvals. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. |
| (8) | There are three categories in evaluating Contingent Resources: Low Estimate, Best Estimate and High Estimate. The resource numbers presented all refer to the Best Estimate category. Best Estimate is a classification of resources described in the Canadian Oil and Gas Evaluation (COGE) Handbook as being considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the Best Estimate. If probabilistic methods are used, there should be a 50% probability (P50) that the quantities actually recovered will equal or exceed the Best Estimate. Best Estimate Contingent Resources are also referred to as “2C Resources”. |
| (9) | These volumes are the arithmetic sums of the Best Estimate Contingent Resources for Christina Lake, Surmont and the Growth Properties. |
A full version of MEG’s Fourth Quarter 2013 Report to Shareholders, including the unaudited financial statements, is available at www.megenergy.com/investors and at www.sedar.com.
A conference call will be held to review MEG’s fourth quarter results at 7:30 a.m. Mountain Time (9:30 a.m. Eastern Time) on Thursday, February 6, 2014. The U.S./Canada toll-free conference call number is 1 888-231-8191. The international/local conference call number is 647-427-7450.
Forward-Looking Information
This document may contain forward-looking information including but not limited to: expectations of future production, revenues, expenses, cash flow, operating costs, SORs, pricing differentials, reliability, profitability and capital investments; estimates of reserves and resources; the anticipated reductions in operating costs as a result of optimization and scalability of certain operations; the anticipated capital requirements, timing for receipt of regulatory approvals, development plans, timing for completion, commissioning and start-up, capacities and performance of the Access Pipeline expansion, the RISER initiative, the Stonefell Terminal, third party barging and rail facilities, the future phases and expansions of the Christina Lake project, the Surmont project and potential projects on the Growth Properties; and the anticipated sources of funding for operations and capital investments. Such forward-looking information is based on management’s expectations and assumptions regarding future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities.
By its nature, such forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: risks associated with the oil and gas industry (e.g. operational risks and delays in the development, exploration or production associated with MEG’s projects; the securing of adequate supplies and access to markets and transportation infrastructure; the availability of capacity on the electrical transmission grid; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and revenues; health, safety and environmental risks; risks of legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws), assumptions regarding and the volatility of commodity prices and foreign exchange rates; and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Christina Lake project and the development of the Corporation’s other projects and facilities. Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive.
The forward-looking information included in this document is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this document is made as of the date of this document and the Corporation assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. For more information regarding forward-looking information see “Notice Regarding Forward Looking Information”, “Risk Factors” and “Regulatory Matters” within MEG’s Annual Information Form dated February 27, 2013 (the “AIF”) along with MEG’s other public disclosure documents. Copies of the AIF and MEG’s other public disclosure documents are available through the SEDAR website (www.sedar.com) or by contacting MEG’s investor relations department.
Estimates of Reserves and Resources
This document contains references to estimates of the Corporation’s reserves and contingent resources. For supplemental information regarding the classification and uncertainties related to MEG’s estimated reserves and resources please see “Independent Reserve and Resource Evaluation” in the AIF.
Non-IFRS Financial Measures
This document includes references to financial measures commonly used in the crude oil and natural gas industry, such as operating earnings, cash flow from operations and cash operating netback. These financial measures are not defined by IFRS as issued by the International Accounting Standards Board and therefore are referred to as non-IFRS measures. The non-IFRS measures used by MEG may not be comparable to similar measures presented by other companies. MEG uses these non-IFRS measures to help evaluate its performance. Management considers operating earnings and cash operating netback important measures as they indicate profitability relative to current commodity prices. Management uses cash flow from operations to measure MEG’s ability to generate funds to finance capital expenditures and repay debt. These non-IFRS measures should not be considered as an alternative to or more meaningful than net income (loss) or net cash provided by operating activities, as determined in accordance with IFRS, as an indication of MEG’s performance. The non-IFRS operating earnings and cash operating netback measures are reconciled to net income (loss), while cash flow from operations is reconciled to net cash provided by operating activities, as determined in accordance with IFRS, under the heading “Non-IFRS Measurements” in MEG’s Fourth Quarter 2013 Report to Shareholders.
MEG Energy Corp. is focused on sustainable in situ oil sands development and production in the southern Athabasca oil sands region of Alberta, Canada. MEG is actively developing enhanced oil recovery projects that utilize SAGD extraction methods. MEG’s common shares are listed on the Toronto Stock Exchange under the symbol “MEG.”
SOURCE MEG Energy Corp.
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