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
-- Trilogy added 14.3 MMBoe of total proved reserves and 27.4 MMBoe of
total proved plus probable reserves, including technical revisions;
-- Trilogy replaced 180 percent of 2016 produced reserves when compared to
total proved reserve additions, and 344 percent when compared to total
proved plus probable reserves;
-- Production decreased in 2016 to 21,822 Boe/d as compared to 27,775 Boe/d
in 2015. The decrease in annual production was attributed primarily to
the disposition of non-core production and the expiry of the Company's
liquids recovery agreement with Aux Sable Canada LP occurring in the
latter part of 2015. The shut-in of uneconomic production (for part of
2016), during lower natural prices and a reduced capital expenditure
budget, further contributed to the decrease. Reported sales volumes for
the fourth quarter of 2016 were higher at 22,565 Boe/d as compared to
21,632 Boe/d for the third quarter;
-- Average realized pricing, before hedges, increased by 22 percent to
$29.79/Boe in the fourth quarter from $24.39/Boe for the previous
quarter. Average realized pricing, before hedges, decreased year over
year by 13 percent from $28.23 to $24.42. Trilogy's 2016 realized price
for its oil (after financial instrument gains) was $61.87/Bbl, an
increase of $12.34/Bbl over its realized price (before financial
instruments);
-- Trilogy implemented significant capital cost efficiencies achieved
mainly through improved drilling and completion practices and decreases
in the cost of the related services. Trilogy drilled 6.0 net wells in
the fourth quarter, for a total of 16.5 net wells to date in 2016 to
evaluate Duvernay and Montney formations. Net capital expenditures
totaled $29.7 million for the fourth quarter ($72.8 million year to
date);
-- Finding and development costs (1) in the year were $12.65/Boe (total
proved reserves) and $8.09/Boe (total proved plus probable reserves);
-- Net debt (1) increased to $588.6 million at the end of 2016 from $544.2
million for the previous year. Capacity under the credit facility at the
end of the quarter was $6.1 million, inclusive of a working capital
deficiency and outstanding letters of credit;
-- Operating expenditures decreased to $69.2 million ($8.67/Boe) in 2016
from $93.1 million ($9.18/Boe) in 2015 on reduced production and
operating cost efficiencies. During the fourth quarter operating
expenditures were $19.1 million ($9.23/Boe) as compared to $17.8 million
($8.90/Boe) for the third quarter on the higher production and on
increased field workover and maintenance projects;
-- Funds flow from operations (1) decreased to $55.9 million for 2016 as
compared to $109.3 million for 2015. $21.8 million was generated in the
fourth quarter as compared to $16.1 million in the third quarter on
higher realized pricing and production, offset, in part by a provision
of $6 million for the Company's previously reported Kaybob Emulsion
Release and approximately $2.5 million on third party downward revenue
adjustment for prior year production allocations.
(1) Refer to Non-GAAP measures in this release and MD&A
Financial and Operating Highlights Table
(In thousand Canadian dollars except per share amounts and where stated otherwise)
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Three Months Ended Year-Ended December 31
December September Change Change
31, 2016 30, 2016 % 2016 2015 %
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FINANCIAL
Petroleum and
natural gas sales 61,834 48,550 27 195,036 286,161 (32)
Funds flow
From
operations(1) 21,824 16,078 36 55,938 109,346 (49)
Per share -
diluted 0.17 0.13 36 0.44 0.87 (49)
Earnings
Loss before tax (24,593) (25,460) (3) (124,508) (177,002) (30)
Per share -
diluted (0.19) (0.20) (4) (0.99) (1.40) (30)
Loss after tax (18,116) (18,629) (3) (93,401) (137,658) (32)
Per share -
diluted (0.14) (0.15) (5) (0.74) (1.09) (32)
Capital
expenditures
Exploration,
development,
land, and
facility 30,413 20,293 50 74,057 80,928 (8)
Acquisitions
(dispositions)
and other - net (725) (80) 806 (1,212) (160,181) (99)
Net capital
expenditures 29,688 20,213 47 72,845 (79,253) (192)
Total assets 1,224,714 1,226,024 (0) 1,224,714 1,266,492 (3)
Net debt(1) 588,618 569,514 3 588,618 544,167 8
Shareholders'
equity 363,898 381,229 (5) 363,898 447,742 (19)
Total shares
outstanding
(thousands)
- As at end of
period (2) 126,101 126,066 126,101 126,024
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OPERATING
Production
Natural gas
(MMcf/d) 93 92 1 91 108 (16)
Oil (Bbl/d) 5,251 3,723 41 4,290 5,577 (23)
Natural gas
liquids (Boe/d) 1,881 2,616 (28) 2,349 4,214 (44)
Total production
(Boe/d @ 6:1) 22,565 21,632 4 21,822 27,775 (21)
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Liquids
Composition
(percentage) 32 29 30 35
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Average prices
before financial
instruments
Natural gas
($/Mcf) 3.17 2.47 28 2.47 3.14 (21)
Crude Oil ($/Bbl) 56.16 52.03 8 49.53 53.07 (7)
Natural gas
liquids ($/Boe) 44.59 40.93 9 40.68 35.52 15
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Average realized
price 29.79 24.39 22 24.42 28.23 (13)
Drilling activity
(gross)
Gas 2 1 100 7 16 (56)
Oil 7 5 40 16 5 220
Total wells 9 6 50 23 21 10
(1) Funds flow from operations and net debt are non-GAAP terms. Please refer
to the advisory on Non-GAAP measures below.
(2) Excluding shares held in trust for the benefit of Trilogy's officers and
employees under the Company's Share Incentive Plan. Includes Common
Shares and Non-voting Shares. Refer to the notes to the Annual Audited
Consolidated Financial Statements for additional information.
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.
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Average Average Average
Cum Oil Cum Gas Oil Rate Gas Rate Prod.
MBbl MMcf Bbl/d MMcf/d Boe/d
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5-6-64-18W5 107 292 405 1.1 591
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02/12-6-64-18W5 76 219 278 0.8 411
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10-31-64-18W5 26 75 200 0.6 486
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02/1-1-64-19W5 63 103 608 1.0 782
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02/2-1-64-19W5 68 78 735 0.9 877
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2-1-64-19W5 32 34 411 0.4 486
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02/4-6-64-18W5 59 79 791 1.1 970
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02/5-6-64-18W5 90 182 892 1.8 1192
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03/4-6-64-18W5 35 31 468 0.4 538
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Sand Lateral Total
Tonnes Number of Length Prod. On Prod.
per stage Stages Meters Days Date
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5-6-64-18W5 20 22 1577 263 Mar 18
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02/12-6-64-18W5 10 22 1566 274 May 12
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10-31-64-18W5 20 28 2680 131 Sept 23
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02/1-1-64-19W5 20 21 1498 102 Oct 16
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02/2-1-64-19W5 20 21 1455 92 Oct 17
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2-1-64-19W5 20 26 1525 77 Oct 20
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02/4-6-64-18W5 20 32 1584 74 Nov 11
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02/5-6-64-18W5 13.5 33 1573 101 Nov 12
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03/4-6-64-18W5 20 32 1581 74 Nov 14
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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.
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Average
Oil/Cond Average Average
Cum Cond Cum Gas Rate Gas Rate Prod.
MBbl MMcf Bbl/d MMcf/d Boe/d
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2/16-17-61-19W5 24 304 237 3.0 736
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12-21-63-17W5 26 39 389 0.6 488
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Condensate
Gas Ratio Sand Conc. Total Prod. On Prod.
Bbl/MMcf t/m Days Date
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2/16-17-61-19W5 79 2.2 102 Nov 10 2016
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12-21-63-17W5 657 2.2 66 Dec 21 2016
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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.
-- Total proved reserves and total proved plus probable reserves at the end
of 2016 were 101.3 MMBoe and 177.4 MMBoe respectively
-- NPV10 for total proved reserves and for total proved plus probable
reserves at the end of 2016 was valued at $936 million and $1,696
million respectively based on McDaniel's December 31, 2016 pricing
forecast
-- Finding and development costs including future development capital were
$12.66/Boe for total proved reserves and $8.09/Boe for total proved plus
probable reserves
-- Reserves life index increased to 22.2 years for total proved plus
probable reserves in 2016 as compared to 15.6 years in 2015
-- Replaced 180 percent of 2016 produced reserves when compared to total
proved reserves additions and 344 percent when compared to total proved
plus probable reserves addition
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:
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Oil Gas NGLs Boe (6:1)
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Reserve Category MBbl MMcf MBoe MBoe
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Proved developed producing 8,338.4 241,735 6,780.3 55,408
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Proved developed nonproducing 2,039.4 14,100 612.8 5,002
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Proved undeveloped 5,621.3 131,182 13,362.1 40,847
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Total Proved 15,999.1 387,017 20,755.2 101,257
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Total Probable 9,813.5 268,839 21,492.1 76,112
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Total P+P 25,812.6 655,856 42,247.3 177,369
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Before tax NPV ($000)
--------------------------------
Reserve Category 0% 5% 10%
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Proved developed producing 853,651 692,823 581,487
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Proved developed nonproducing 73,656 58,459 48,208
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Proved undeveloped 705,833 463,416 306,371
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Total Proved 1,633,139 1,214,698 936,066
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Total Probable 1,843,253 1,137,868 760,080
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Total P+P 3,476,392 2,352,566 1,696,146
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Notes
(i) Reserve values were determined by McDaniel as of December 31, 2016,
using the forward-pricing assumptions in effect by the firm as at that
date.
(ii) McDaniel evaluated 100 percent of Trilogy's reserves.
(iii) No value has been assigned to tangible assets other than those
associated with proved producing reserves.
While Trilogy plans to develop the proved undeveloped and the probable undeveloped reserves over the next five years, the fruition of such plans depends heavily upon numerous unforeseen factors, many of which are outside of the control of the Company. These factors include, but are not limited to, fluctuations in commodity prices which can affect the funding for these projects, causing them to be accelerated, deferred or cancelled. Changing technical and production factors can also affect the timely development of these projects.
The following table summarizes the future development capital Trilogy has included in its 2016 reserves evaluation for the next 5 years.
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Capital for Future Development ($ millions)
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Total Proved plus
Year Total Proved Probable
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2017 118.8 136.5
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2018 268.3 330.5
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2019 237.3 308.6
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2020 49.3 277.5
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2021 10.4 138.0
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2022 - 0.5
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684.0 1,191.6
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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.
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Total Proved
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Oil Gas NGL Boe
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MBbl MMcf MBoe MBoe
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December 31, 2015 14,902 366,239 18,959 94,901
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Extensions & Improved Recovery 3,201 17,782 515 6,679
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Technical Revisions -506 41,482 2,229 8,637
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Acquisitions 0 97 2 18
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Dispositions 0 0 0 0
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Economic Factors -27 -5,240 -90 -990
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Production -1,570 -33,343 -860 -7,987
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December 31, 2016 15,999 387,017 20,755 101,257
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Total Proved + Probable
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Oil Gas NGL Boe
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MBbl MMcf MBbl MBoe
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December 31, 2015 20,408 589,351 39,282 157,915
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Extensions & Improved Recovery 8,097 64,018 1,437 20,204
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Technical Revisions -1,030 42,662 2,511 8,592
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Acquisitions 0 124 2 23
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Dispositions 0 0 0 0
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Economic Factors -93 -6,956 -126 -1,378
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Production -1,570 -33,343 -860 -7,987
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December 31, 2016 25,813 655,856 42,247 177,369
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Notes (i) Columns and rows may not add due to rounding
In the 2016 year end reserves, McDaniel used the following price forecast for the evaluation which was developed by them.
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WTI @ EDM REF EXCHANGE
CUSHING PRICE HENRY HUB AECO C RATE
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Year $US/BBL $C/BBL US$/MMBTU C$/MMBTU CDN/US
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2017 55.00 69.80 3.40 3.40 0.75
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2018 58.70 72.70 3.20 3.15 0.78
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2019 62.40 75.50 3.35 3.30 0.80
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2020 69.00 81.10 3.65 3.60 0.83
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2021 75.80 86.60 4.00 3.90 0.85
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Next 5 years average 80.44 91.88 4.23 4.20 0.85
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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 $8.09/Boe for total proved plus probable reserves.
Finding and development costs for the past 3 years are shown in the table below.
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Total Proved Total Proved plus Probable
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Capital Reserves F&D Capital Reserves F&D
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$MM MBoe $/Boe $MM MBoe $/Boe
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2014 766.4 30,873 $ 24.82 984.4 47,379 $20.78
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2015 294.2 14,612 $20.13 528.1 37,481 $14.09
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2016 181.6 14,343 $12.65 222.1 27,441 $8.09
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3 Year average 1,242.1 59,828 $20.76 1,734.6 112,300 $15.45
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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:
-- hedged 2,000 Bbl/d of crude oil for calendar 2017 at NYMEX $71.17 CDN
-- hedged 1,000 Bbl/d of crude oil for calendar 2017 at NYMEX $54.46 USD
-- collared 500 Bbl/d of crude oil for calendar 2017 between $38.00 and
$57.50 USD WTI
-- collared 500 Bbl/d of crude oil for calendar 2017 between $42.00 and
$52.90 USD WTI
-- Throughout January and February 2017, Trilogy accelerated the
realization and receipt of gains totaling $3.5 million USD ($4.6 million
CDN) on 40,000 MMBTU/d of financial sales contracts, originally put in
place for calendar 2017.
Outlook
-- Trilogy's Board of Directors approved a 2017 capital budget of $130
million.
-- For 2017, Trilogy is forecasting its capital expenditures to be less
than its projected funds flow from operations while growing its
production by approximately 10 percent over 2016 average production to
approximately 24,000 Boe/d, based on current strip pricing and taking
into account current Company hedges;
-- The Company plans to invest approximately $60 million into the Kaybob
Montney oil pool in 2017 to drill 15 horizontal net wells, complete 18
net wells and complete infrastructure projects that will reduce ongoing
operating costs in this area;
-- Trilogy also plans to invest approximately $25 million into the Presley
Montney gas pool in 2017 to drill, complete and tie-in 5.25 net wells;
-- The balance of the capital budget will be primarily allocated to
developing Trilogy's Duvernay assets in the second half of the year,
with lesser amounts allocated to infrastructure, workovers, tie-ins and
projects designed to reduce operating costs;
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:
Average production 24,000 Boe/d (approx. 35 percent oil and NGLs) Average operating costs $8.50 /Boe Capital expenditures $130 million
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 http://media3.marketwire.com/docs/1088033_report.pdf. These reports will also be made available through Trilogy's website at www.trilogyenergy.com and SEDAR at www.sedar.com.
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:
-- business strategy and objectives for 2017 and beyond;
-- drilling, completion and infrastructure plans for the Company's Kaybob
Montney oil and gas assets and Duvernay play, among others, and the
timing, cost payout and other anticipated benefits thereof;
-- forecast 2017 annual production levels;
-- planned 2017 capital expenditures, the allocation and timing thereof and
Trilogy's intention to execute its capital budget within annual funds
flow from operations;
-- operating, finding and development, decommissioning, asset retirement,
restoration and other costs and the anticipated results of Trilogy's
cost cutting measures;
-- the capacity under and potential liabilities relating to long-term
transportation, fractionation and other marketing, midstream and forward
contracts;
-- anticipated funds flow from operations and other measures of profit,
-- expectations regarding future commodity prices for crude oil, natural
gas, NGLs and related products and the potential impact to Trilogy of
commodity price fluctuations;
-- estimated reserves, the discounted present value of future net revenue
therefrom and the Company's plans to develop same including the capital
required, the timing thereof and the price forecasts used in calculating
the foregoing;
-- plans to accelerate development of some or all of the Company's Duvernay
shale assets;
-- the ability to profitably exploit Trilogy's assets, grow production and
generate long-term shareholder value;
-- projected results of hedging contracts and other financial instruments;
-- Management's current estimate of the financial impact of the recent
Kaybob North Montney pipeline release and third party prior year revenue
adjustment; and
-- other expectations, beliefs, plans, goals, objectives, assumptions,
information and statements about possible future events, conditions, and
results of operations or performance.
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:
-- future crude oil, natural gas, condensate, NGLs and other commodity
pricing and supply;
-- funds flow from operations and cash flow consistent with expectations;
-- current reserves estimates;
-- credit facility availability and access to sources of funding for
Trilogy's planned operations and expenditures;
-- the ability of Trilogy to service and repay its debt when due;
-- current production forecasts and the relative mix of crude oil, natural
gas and NGLs therein;
-- geology applicable to Trilogy's land holdings;
-- the extent and development potential of Trilogy's assets (including,
without limitation, Trilogy's Kaybob area Montney oil and gas assets and
the Duvernay Shale play, among others);
-- the ability of Trilogy and its industry partners to obtain drilling and
operational results, improvements and efficiencies consistent with
expectations (including in respect of anticipated production volumes,
reserves additions and NGL yields);
-- well economics;
-- decline rates;
-- foreign currency, exchange and interest rates;
-- royalty rates, taxes and capital, operating, general & administrative
and other costs and expenses;
-- assumptions regarding royalties and expenses and the applicability and
continuity of royalty regimes and government incentive programs to
Trilogy's operations;
-- general business, economic, industry and market conditions;
-- projected capital investment levels and the successful and timely
implementation of capital projects;
-- anticipated timelines and budgets being met in respect of drilling
programs and other operations;
-- the ability of Trilogy to obtain equipment, services, supplies and
personnel in a timely manner and at an acceptable cost to carry out its
evaluations and activities;
-- the ability of Trilogy to secure adequate product processing,
transportation, fractionation and storage capacity on acceptable terms
or at all and assumptions regarding the timing and costs of run-times,
outages and turnarounds;
-- the ability of Trilogy to market its oil, natural gas, condensate, other
NGLs and other products successfully to current and new customers;
-- expectation that counterparties will fulfill their obligations under
operating, processing, marketing and midstream agreements;
-- the timely receipt of required regulatory approvals;
-- the continuation of assumed tax regimes, estimates and projections in
respect of the application of tax laws and estimates of deferred tax
amounts, tax assets and tax pools;
-- the extent of Trilogy's liabilities; and
-- assumptions used in calculating the provisions made for the cost of the
Kaybob North Montney pipeline release and the third party prior year
production reallocations.
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:
-- fluctuations in crude oil, natural gas, condensate and other natural gas
liquids and commodity prices;
-- the ability to generate sufficient funds flow from operations and obtain
financing on acceptable terms to fund planned exploration, development,
construction and operational activities and to meet current and future
obligations ;
-- the possibility that Trilogy will not commercially develop its Duvernay
shale assets in the near future or at all;
-- uncertainties as to the availability and cost of financing;
-- Trilogy's ability to satisfy maintenance covenants within its credit and
debt arrangements;
-- the risk and effect of a downgrade in Trilogy's credit rating;
-- fluctuations in foreign currency, exchange rates and interest rates;
-- the risks of the oil and gas industry, such as operational risks in
exploring for, developing and producing crude oil, natural gas,
condensate and other natural gas liquids, and market demand;
-- risks and uncertainties involving the geology of oil and gas;
-- the uncertainty of reserves estimates reserves life;
-- the uncertainty of estimates and projections relating to future
production and NG yields as well as costs and expenses;
-- the ability of Trilogy to add production and reserves through
development and exploration activities and acquisitions;
-- Trilogy's ability to secure adequate product processing, transmission,
transportation, fractionation and storage capacity on acceptable terms
and on a timely basis or at all;
-- potential disruptions or unexpected technical difficulties in designing,
developing, or operating new, expanded, or existing pipelines or
facilities (including third party operated pipelines and facilities);
-- risks inherent in Trilogy's marketing operations, including credit and
other financing risks and the risk that Trilogy may not be able to enter
into arrangements for the sale of its sales volumes;
-- volatile business, economic and market conditions;
-- general risks related to strategic and capital allocation decisions,
including potential delays or changes in plans with respect to
exploration or development projects or capital expenditures and
Trilogy's ability to react to same;
-- availability of equipment, goods, services and personnel in a timely
manner and at an acceptable cost;
-- health, safety, security and environmental risks;
-- the timing and cost of future abandonment and reclamation obligations
and potential liabilities for environmental damage and contamination;
-- risks and costs associated with environmental, regulatory and
compliance, including those potentially associated with hydraulic
fracturing, greenhouse gases and "climate change" and the cost to
Trilogy in order to comply with same;
-- weather conditions;
-- the possibility that government policies, regulations or laws may
change, including risks related to the imposition of moratoriums;
-- the possibility that regulatory approvals may be delayed or withheld;
-- risks associated with Trilogy's ability to enter into and maintain
leases and licenses;
-- uncertainty with regard to royalty payments and the applicability of and
changes to royalty regimes and incentive programs including, without
limitation, applicable royalty incentive regimes and the Modernized
Royalty Framework, the Emerging Resources Program and the Enhanced
Hydrocarbon Recovery Program, among others;
-- imprecision in estimates of product sales, commodity prices, capital
expenditures, tax pools, tax deductions available to Trilogy, changes to
and the interpretation of tax legislation and regulations;
-- uncertainty regarding results of objections to Trilogy's exploration and
development plans by third party industry participants, aboriginal and
local populations and other stakeholders;
-- risks associated with existing and potential lawsuits, regulatory
actions, audits and assessments;
-- changes in land values paid by industry;
-- risks associated with Trilogy's mitigation strategies including
insurance and hedging activities;
-- risks related to the actions and financial circumstances of Trilogy
agents and contractors, counterparties and joint venture partners,
including renegotiation of contracts;
-- risks relating to cybersecurity, vandalism, and terrorism;
-- the ability of management to execute its business plan;
-- the risk that the assumptions used by Management to estimate the
provision for the costs resulting from the recent Kaybob North Montney
pipeline release and the third party prior year production reallocation
prove to be incorrect; and
-- other risks and uncertainties described elsewhere in this document and
in Trilogy's other filings with Canadian securities authorities,
including its Annual Information Form.
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)
