Trilogy Energy Corp. Announces Financial and Operating Results for the Quarter and Year-Ended December 31, 2016
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 03/07/17 -- Trilogy Energy Corp. (TSX: TET) ("Trilogy") is pleased to announce its financial and operating results for the quarter and year-ended December 31, 2016.
Financial and Operating Highlights
Financial and Operating Highlights Table
(In thousand Canadian dollars except per share amounts and where stated otherwise)
Operations Update for the Fourth Quarter 2016
Trilogy''s average production during the fourth quarter of 2016 was 22,565 Boe/d (32 percent liquids), resulting in annual 2016 average production of 21,822 Boe/d (30 percent liquids). Production was approximately 23,800 Boe/d (36 percent liquids) in December 2016, and increased to approximately 24,500 Boe/d (38 percent liquids) in January 2017. During the fourth quarter of 2016, Trilogy recorded a $6.0 million provision for the Kaybob emulsion release reported in October 2016 and $2.5 million (inclusive of $3.3 million revenues less royalty and operating expenses of $0.6 and $0.2, respectively) for a third party downward revenue adjustment relating to prior year production allocations. Third party revenue adjustments negatively impacted full year 2016 average production by an estimated 115 Boe/d.
Funds flows from operations were $21.8 million for the fourth quarter 2016 and $55.9 million for the year. Excluding the one-time adjustments for the emulsion release and revenue allocation noted above, flow from operations would have been approximately $30 million for the fourth quarter and $64 million for the year.
Montney Oil Update
Based on encouraging completion results from the first quarter 2016 Montney horizontal oil wells, the Company increased its 2016 Montney drilling activity from the 2 wells that were initially planned to a total of 12 wells for the year. Nine of these wells were completed prior to the end of 2016; the remaining 3 were completed in January 2017 and producing through the Montney oil battery in late February 2017.
Continued improvements to Trilogy''s Montney oil well drilling and completion program resulted in year-over-year well costs declining by approximately 30 percent while productivity generally increased. Cost savings were achieved in the drilling operations through the utilization of multi-well pads and high performance drilling systems. The shift from hydrocarbon-based fracture to water-based fracture stimulations significantly reduced completion costs and allowed the Company to economically increase proppant volume and decrease stage spacing, thereby better distributing proppant along the length of the lateral wellbore.
Trilogy varied sand volumes from 10 tonnes per stage in the Company''s original horizontal Montney oil wells to as much as 20 tonnes per stage in recent wells. At the same time, stage spacing was reduced from 75 meters per stage in the original wells to 50 to 65 meters in the fourth quarter wells. In addition, substantially higher completion pump rates have increased the size and complexity of Trilogy''s fracture stimulations. All of these factors combined have contributed to higher initial well productivity as compared to the Company''s first generation Montney oil wells.
Incorporating the efficiencies and learnings from its 2016 Montney drilling and completion program, Trilogy plans to drill 15 horizontal Montney oil wells and complete 18 wells in 2017. The capital investment Trilogy has made into the Montney oil gathering and processing infrastructure has resulted in Trilogy reducing its operating cost structure in this area to $6.60/Boe for 2016. For the month of January 2017, Trilogy realized a $33.89/Boe operating netback for its Montney oil operations, when WTI averaged USD $52.61/Bbl and natural gas averaged $3.32/GJ. Assuming $2.9 million capital costs to drill, complete and equip a Montney oil well, wells are expected to reach a capital payout after 85 MBoe of production (60 MBbl of crude oil and 150 MMcf of natural gas). Trilogy''s 10 tonne type curve for the west side of the pool forecasts 60 MBbl of cumulative oil production after approximately 6 producing months, while new wells with higher fracture intensity and sand concentration may reach 60 MBbl in as little as 2 to 3 months of production.
The following table updates production results to February 28, 2017 for the 9 horizontal Montney oil wells that were drilled, completed and brought on production in 2016. The variable results reflect the evolution of completion techniques described above.
Duvernay Update
Trilogy successfully drilled, completed and tied in 2 (2.0 net) horizontal Duvernay wells in 2016. Each well was drilled and completed on a single well pad at a cost of approximately $10.2 million per well. The significant reduction in costs relative to previous Duvernay wells reflects improvements in efficiencies and operational performance during the drilling and completion operations.
The 02/16-17-61-19W5 well was placed on production on November 10, 2016 and has produced for 3 months since that time, producing an aggregate of 24 MBbl of condensate and 304 MMcf of natural gas up to February 28, 2017. Production was initially restricted through a downhole choke, which was removed in January 2017. The condensate to gas ratio has averaged approximately 79 Bbl/MMcf in the initial 3 producing months.
The 12-21-63-17W5 well was drilled to manage a nine section block of acreage that was set to expire at the end of 2016. The well was brought on production on December 21, 2016 and has produced an aggregate of approximately 26 MBbls of crude oil/condensate (42 degree API, density of 814 kg/m3) and 39 MMcf of natural gas in the past 2 months. The condensate/oil to gas ratio has averaged 657 Bbl/MMcf in the initial 2 producing months.
Trilogy is very encouraged by its own Duvernay results as well as the progress that has been made by industry to begin the commercial development of the Duvernay. As Trilogy continues to develop its Duvernay shale assets, it may require additional sources of funding to accelerate the development of some or all of its acreage within the Duvernay play. This may offset Trilogy''s working interest in, and the reserves and future net revenue attributable to these or other properties. Trilogy has processing capacity in place to produce volumes from its Duvernay development plan for the initial two to three year period; however, to deliver on the longer term Duvernay development plan, Trilogy will require access to additional operated and non-operated natural gas processing and NGL handling infrastructure.
2016 Year End Reserves Report Highlights
The following is a summary of Trilogy''s 2016 year end reserves and reserves value, as evaluated and reported by the independent engineering firm McDaniel & Associates Consultants Ltd. (McDaniel"). The reserves report has been prepared in accordance with National Instrument 51-101 definitions, standards and procedures.
Trilogy has dedicated substantial resources and capital to further its knowledge base for the Montney and Duvernay plays over the past number of years. Over the past year, industry has made significant progress in improving drilling and completion techniques and reducing the associated costs. These advancements have enabled Trilogy the opportunity to generate and refine several production type curves for its land base, as well as other estimates, including estimates for recoverable reserves, liquid ratios, infrastructure requirements and operating costs related to these plays. Accordingly, the continued advancements in Trilogy''s Montney and Duvernay resource plays have contributed to further de-risking the plays and have afforded Trilogy the opportunity to book additional proved and probable undeveloped reserves in the Kaybob area.
The results of the 2016 year end reserves report are summarized in the table below:
While Trilogy plans to develop the proved undeveloped and the probable undeveloped reserves over the next five years, the fruition of such plans depends heavily upon numerous unforeseen factors, many of which are outside of the control of the Company. These factors include, but are not limited to, fluctuations in commodity prices which can affect the funding for these projects, causing them to be accelerated, deferred or cancelled. Changing technical and production factors can also affect the timely development of these projects.
The following table summarizes the future development capital Trilogy has included in its 2016 reserves evaluation for the next 5 years.
Reserves Reconciliation
For 2016, total proved reserves were revised upward by 8.6 MMBoe and total proved plus probable reserves were essentially flat year over year. The majority of the positive technical revisions were due to adjustments made to the Presley Montney gas wells, and positive reserve adjustments to the Duvernay shale gas wells and the associated natural gas liquids.
Lower commodity price forecasts at the end of 2016 resulted in negative adjustments of 0.99 MMBoe of total proved reserves and 1.38 MMBoe of total proved plus probable reserves due to economic factors.
The following table below summarizes the reserves reconciliation for 2016.
In the 2016 year end reserves, McDaniel used the following price forecast for the evaluation which was developed by them.
Finding and Development Costs
Since inception, Trilogy has successfully exploited many of the opportunities afforded by its land base. Its success rate reflects the high quality of the Company''s prospect inventory, its undeveloped land base and its producing asset base as well as the technical expertise of Trilogy''s staff. The reserve potential of these lands, both developed and undeveloped, is expected to continue to provide Trilogy with low cost reserve additions in the future.
In 2016, Trilogy spent approximately $74.2 million and booked approximately 5.6 MMBoe and 7.2 MMBoe for total proved and for total proved plus probable reserves respectively for this capital. Based on the capital spent during the year, Trilogy''s finding and development costs for the total proved reserves is $13.07/Boe and for the total proved plus probable reserves is $10.31/Boe.
Finding and development costs including future development capital for 2016 are reported to be $12.65/Boe for total proved reserves and $8.09/Boe for total proved plus probable reserves.
Finding and development costs for the past 3 years are shown in the table below.
When calculated over the three-year period ended December 31, 2016, F&D costs were $20.76/Boe for total proved reserves and $15.45/Boe for total proved plus probable reserves. Calculating finding and development costs over a longer period reduces the effect of spending capital in one year and booking reserves in the following year and reduces the impact of technical revisions.
2017 Hedge Update
Trilogy has hedged approximately 17 percent of its forecast 2017 production to lock in expected returns from wells drilled in its 2017 capital spending program. Details of the hedges are as follows:
Outlook
Trilogy plans to execute a 2017 capital spending budget that is within anticipated 2017 funds flow based on Trilogy''s 2017 production expectations and forecasted pricing. The level of capital to be allocated to Duvernay projects will be reflective of commodity prices and will be weighted to the second half of 2017.
Given the foregoing, Trilogy is reaffirming 2017 annual guidance as follows:
Additional Information
Trilogy''s financial and operating results for the fourth quarter of 2016, including the Annual Report, Management''s Discussion and Analysis and the Company''s Audited Annual Consolidated Financial Statements and related notes as at and for the year-ended December 31, 2016 can be obtained at . These reports will also be made available through Trilogy''s website at and SEDAR at .
About Trilogy
Trilogy is a petroleum and natural gas-focused Canadian energy corporation that actively develops, produces and sells natural gas, crude oil and natural gas liquids. Trilogy''s geographically concentrated assets are primarily, high working interest properties that provide abundant low-risk infill drilling opportunities and good access to infrastructure and processing facilities, many of which are operated and controlled by Trilogy. Trilogy''s common shares are listed on the Toronto Stock Exchange under the symbol "TET".
Non-GAAP Measures
Certain measures used in this document, including "adjusted EBITDA", "consolidated debt", "finding and development costs", "funds flow from operations", "operating income", "net debt", "operating netback", "payout ratio", "recycle ratio" and "senior debt" collectively the "Non GAAP measures" do not have any standardized meaning as prescribed by IFRS and previous GAAP and, therefore, are considered Non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Trilogy to provide Shareholders and potential investors with additional information regarding the Company''s liquidity and its ability to generate funds to finance its operations. However, given their lack of standardized meaning, such measurements are unlikely to be comparable to similar measures presented by other issuers.
"Adjusted EBITDA" refers to "Funds flow from operations" plus cash interest, tax expenses, certain other items (accrued cash remuneration costs for its employees - deducted from EBITDA when paid) that do not appear individually in the line items of the Company''s financial statements in addition to pro-forma adjustments for properties acquired or disposed of in the period and the exclusion of revenues or losses of an extraordinary and non-recurring nature.
"Consolidated debt" generally includes all long-term debt plus any issued and undrawn letters of credit, less any cash held.
"Finding and development costs" refers to all capital expenditures and costs of acquisitions, excluding expenditures where the related assets were disposed of by the end of the year, and including changes in future development capital on a total proved or total proved plus probable basis. "Finding and development costs per Barrel of oil equivalent" ("F&D $/Boe") is calculated by dividing finding and development costs by the current year''s reserve extensions, discoveries and revisions on a total proved or total proved plus probable reserve basis. Management uses finding and development costs as a measure to assess the performance of the Company''s resources required to locate and extract new hydrocarbon reservoirs.
"Funds flow from operations" refers to the cash flow from operating activities before net changes in operating working capital as shown in the consolidated statements of cash flows. Management utilizes funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments.
"Operating income" is equal to petroleum and natural gas sales before financial instruments and bad debt expenses minus royalties, operating charges, and transportation costs. Management uses this metric to measure the discrete operating results of its oil and gas properties.
"Operating netback" refers to operating income plus realized financial instrument gains and losses and other income minus actual decommissioning and restoration costs incurred. Operating netback provides management with a more fulsome metric on its oil and gas properties considering strategic decisions (for example, hedging programs) and associated full life cycle charges.
"Net debt" is calculated as current liabilities minus current assets plus long-term debt. Management utilizes net debt as a key measure to assess the liquidity of the Company.
"Recycle ratio" is equal to "Operating netback" on a production barrel of oil equivalent for the year divided by "F&D $/Boe" (computed on a total proved or total proved plus probable reserve basis as applicable). Management uses this metric to measure the profitability of the Company in turning a barrel of reserves into a barrel of production.
"Senior debt" is generally defined as "Consolidated debt" but excluding any indebtedness under the Senior Unsecured Notes.
Investors are cautioned that the Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with IFRS, as set forth above, or other measures of financial performance calculated in accordance with IFRS.
Forward-Looking Information
Certain statements included in this document (including this MD&A and the Operations Update) constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "budget", "goal", "objective", "possible", "probable", "projected", "scheduled", or state that certain actions, events or results "may", "could", "should", "would", "might" or "will" be taken, occur or be achieved, or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this document include but are not limited to statements regarding:
Statements regarding "reserves" are 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.
Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Trilogy believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Trilogy can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Trilogy and described in the forward-looking statements or information. These risks and uncertainties include but are not limited to:
The foregoing lists are not exhaustive. Additional information on these and other factors which could affect the Company''s operations or financial results are included in the Company''s most recent Annual Information Form and in other documents on file with the Canadian Securities regulatory authorities. The forward-looking statements or information contained in this document are made as of the date hereof and Trilogy undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Oil and Gas Advisory
This document contains disclosure expressed as "Boe", "MBoe", "Boe/d", "Mcf", "Mcf/d", "MMcf", "MMcf/d", "Bcf", "Bbl", and "Bbl/d". All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1). Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil 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. For Q4 2016, the ratio between Trilogy''s average realized oil price and the average realized natural gas price was approximately 18:1 ("Value Ratio"). The Value Ratio is obtained using the Q4 2016 average realized oil price of $56.16 (CAD$/Bbl) and the Q4 2016 average realized natural gas price of $3.17 (CAD$/Mcf). This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value.
Contacts:
J.H.T. (Jim) Riddell, Chief Executive Officer
J.B. (John) Williams, President and Chief Operating Officer
M.G. (Michael) Kohut, Chief Financial Officer
Trilogy Energy Corp.
1400 - 332 - 6th Avenue S.W.
Calgary, Alberta T2P 0B2
(403) 290-2900
(403) 263-8915 (FAX)
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Datum: 07.03.2017 - 16:25 Uhr
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