Trilogy Energy Corp. Announces Financial and Operating Results for the Quarter and Year-Ended December 31, 2016

March 7, 2017

CALGARY, ALBERTA–(Marketwired – March 7, 2017) – 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)

		Three Months Ended						Year-Ended December 31
		December 31, 2016		September 30, 2016		Change %		2016		2015		Change %
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
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	)
	Liquids Composition (percentage)	32		29				30		35
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
	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.

	Cum Oil MBbl	Cum Gas MMcf	Average Oil Rate Bbl/d	Average Gas Rate MMcf/d	Average Prod. Boe/d	Sand Tonnes per stage	Number of Stages	Lateral Length Meters	Total Prod. Days	On Prod. Date
5-6-64-18W5	107	292	405	1.1	591	20	22	1577	263	Mar 18
02/12-6-64-18W5	76	219	278	0.8	411	10	22	1566	274	May 12
10-31-64-18W5	26	75	200	0.6	486	20	28	2680	131	Sept 23
02/1-1-64-19W5	63	103	608	1.0	782	20	21	1498	102	Oct 16
02/2-1-64-19W5	68	78	735	0.9	877	20	21	1455	92	Oct 17
2-1-64-19W5	32	34	411	0.4	486	20	26	1525	77	Oct 20
02/4-6-64-18W5	59	79	791	1.1	970	20	32	1584	74	Nov 11
02/5-6-64-18W5	90	182	892	1.8	1192	13.5	33	1573	101	Nov 12
03/4-6-64-18W5	35	31	468	0.4	538	20	32	1581	74	Nov 14

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.

	Cum Cond MBbl	Cum Gas MMcf	Average Oil/Cond Rate Bbl/d	Average Gas Rate MMcf/d	Average Prod. Boe/d	Condensate Gas Ratio Bbl/MMcf	Sand Conc. t/m	Total Prod. Days	On Prod. Date
2/16-17-61-19W5	24	304	237	3.0	736	79	2.2	102	Nov 10 2016
12-21-63-17W5	26	39	389	0.6	488	657	2.2	66	Dec 21 2016

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:

	Oil	Gas	NGLs	Boe (6:1)	Before tax NPV ($000)
Reserve Category	MBbl	MMcf	MBoe	MBoe	0%	5%	10%
Proved developed producing	8,338.4	241,735	6,780.3	55,408	853,651	692,823	581,487
Proved developed nonproducing	2,039.4	14,100	612.8	5,002	73,656	58,459	48,208
Proved undeveloped	5,621.3	131,182	13,362.1	40,847	705,833	463,416	306,371
Total Proved	15,999.1	387,017	20,755.2	101,257	1,633,139	1,214,698	936,066
Total Probable	9,813.5	268,839	21,492.1	76,112	1,843,253	1,137,868	760,080
Total P+P	25,812.6	655,856	42,247.3	177,369	3,476,392	2,352,566	1,696,146

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.

	Capital for Future Development ($ millions)
Year	Total Proved	Total Proved plus Probable
2017	118.8	136.5
2018	268.3	330.5
2019	237.3	308.6
2020	49.3	277.5
2021	10.4	138.0
2022	–	0.5
	684.0	1,191.6

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.

	Total Proved				Total Proved + Probable
	Oil	Gas	NGL	Boe	Oil	Gas	NGL	Boe
	MBbl	MMcf	MBoe	MBoe	MBbl	MMcf	MBbl	MBoe
December 31, 2015	14,902	366,239	18,959	94,901	20,408	589,351	39,282	157,915
Extensions & Improved Recovery	3,201	17,782	515	6,679	8,097	64,018	1,437	20,204
Technical Revisions	-506	41,482	2,229	8,637	-1,030	42,662	2,511	8,592
Acquisitions	0	97	2	18	0	124	2	23
Dispositions	0	0	0	0	0	0	0	0
Economic Factors	-27	-5,240	-90	-990	-93	-6,956	-126	-1,378
Production	-1,570	-33,343	-860	-7,987	-1,570	-33,343	-860	-7,987
December 31, 2016	15,999	387,017	20,755	101,257	25,813	655,856	42,247	177,369

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.

	WTI @ CUSHING	EDM REF PRICE	HENRY HUB	AECO C	EXCHANGE RATE
Year	$US/BBL	$C/BBL	US$/MMBTU	C$/MMBTU	CDN/US
2017	55.00	69.80	3.40	3.40	0.75
2018	58.70	72.70	3.20	3.15	0.78
2019	62.40	75.50	3.35	3.30	0.80
2020	69.00	81.10	3.65	3.60	0.83
2021	75.80	86.60	4.00	3.90	0.85
Next 5 years average	80.44	91.88	4.23	4.20	0.85

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.

	Total Proved			Total Proved plus Probable
	Capital	Reserves	F&D	Capital	Reserves	F&D
	$MM	MBoe	$/Boe	$MM	MBoe	$/Boe
2014	766.4	30,873	$ 24.82	984.4	47,379	$20.78
2015	294.2	14,612	$20.13	528.1	37,481	$14.09
2016	181.6	14,343	$12.65	222.1	27,441	$8.09
3 Year average	1,242.1	59,828	$20.76	1,734.6	112,300	$15.45

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 (~ 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.

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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