Trilogy Energy Corp. Announces Financial and Operating Results for the Quarter-Ended March 31, 2017

May 8, 2017

CALGARY, ALBERTA–(Marketwired – May 8, 2017) –

Trilogy Energy Corp. (TSX:TET) (“Trilogy”) is pleased to announce its financial and operating results for the quarter-ended March 31, 2017.

Financial and Operating Highlights

Reported sales volumes for the first quarter of 2017 increased 11 percent to 25,133 Boe/d (38 percent liquids) as compared to 22,565 Boe/d (32 percent liquids) for the fourth quarter of 2016. The increase was attributed primarily to new well production coming on stream in the quarter;
Average realized pricing, after hedges, increased by 13 percent to $35.97/Boe in the first quarter of 2017 from $31.92/Boe for the previous quarter. Year over year, average realized pricing, after hedges, also increased 48 percent from the first quarter of 2016;
Funds flow from operations⁽¹⁾ increased 67 percent to $36.4 million for the first quarter of 2017 as compared to $21.8 million for the previous quarter. Year over year, funds flow from operations increased by 338 percent from $8.3 million in the first quarter of 2016.
Trilogy drilled 9.0 net wells in the first quarter. Net capital expenditures totaled $41.0 million for the first quarter compared to $29.7 million for the fourth quarter of 2016;
Net debt⁽¹⁾ decreased to $583.8 million as at March 31, 2017 from $588.6 million as at December 31, 2016;
During the quarter, Trilogy accelerated the realization and receipt of natural gas derivative contract gains totaling $3.5 million USD ($4.6 million CDN).
Subsequent to the quarter, Trilogy:
- Renewed its revolving credit facility agreement with its lenders whereby commitments under this facility were set at $300 million. The maturity date was extended to April 30, 2019;
- Announced that it had agreed to sell certain oil and gas properties in the Grande Prairie area for cash consideration of $50 million (before customary adjustments). The disposition is expected to close before the end of May 2017. Proceeds are expected to be used to repay amounts drawn under Trilogy’s revolving credit facility. Pro-forma capacity under Trilogy’s revolving credit facility as at March 31, 2017, after giving effect to the disposition, is expected to approximate $49 million;
- Entered into forward sales contracts for 30,000 MMBTU/d from May 2017 through to December 2017 at an average price of $3.39 USD/MMBTU.

⁽¹⁾	Refer to Non-GAAP measures

Financial and Operating Highlights Table

(In thousand Canadian dollars except per share amounts and where stated otherwise)

		Three Months Ended
		March 31,		December 31,
		2017		2016		Change %
FINANCIAL
Petroleum and natural gas sales		76,089		61,834		23
Funds flow
	From operations⁽¹⁾	36,382		21,824		67
	Per share – diluted	0.29		0.17		67
Earnings
	Income (loss) before tax	10,874		(24,593	)	(144	)
	Per share – diluted	0.09		(0.19	)	(144	)
	Income (loss) after tax	7,694		(18,116	)	(142	)
	Per share – diluted	0.06		(0.14	)	(143	)
Capital expenditures
	Exploration, development, land, and facility	41,658		30,413		37
	Acquisitions (dispositions) and other – net	(675	)	(725	)	(7	)
Net capital expenditures		40,983		29,688		38
Total assets		1,230,978		1,224,714		1
Net debt⁽¹⁾		583,777		588,618		(1	)
Shareholders’ equity		372,525		363,898		2
Total shares outstanding (thousands)
	– As at end of period ⁽²⁾	126,106		126,101		–
OPERATING
Production
	Natural gas (MMcf/d)	93		93		–
	Oil (Bbl/d)	6,305		5,251		20
	Condensate (Boe/d)	2,059		1,200		72
	Natural gas liquids (Boe/d)	1,207		682		77
	Total production (Boe/d @ 6:1)	25,133		22,565		11
	Liquids Composition (percentage)	38		32
Average prices after financial instruments
	Natural gas ($/Mcf)	3.63		3.12		16
	Crude Oil ($/Bbl)	62.69		66.24		(5	)
	Condensate ($/Boe)	63.25		59.84		6
	Natural gas liquids ($/Boe)	32.95		17.75		86
Average realized price ($/Boe)		35.97		31.92		13
Drilling activity (gross)
	Gas	4		2		100
	Oil	6		7		(14	)


⁽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 First Quarter 2017

Trilogy’s first quarter 2017 production was 25,133 Boe/d (38 percent oil and natural gas liquids), an increase of 11 percent from fourth quarter 2016 production of 22,565 Boe/d (32 percent oil and natural gas liquids). The increase in first quarter production reflects the impact of new horizontal Montney and Duvernay wells drilled and completed in the fourth quarter 2016 and first quarter 2017. Three wells drilled late in the fourth quarter of 2016 were fracture stimulated in January and on production in February 2017. Trilogy drilled 6 horizontal Montney oil wells during the first quarter, of which 3 were completed and on production in late March.

Funds flow from operations was $36.4 million and net capital expenditures were $41.0 million for the first quarter. Second quarter capital spending is estimated to be between $20-$25 million, depending on weather and ground conditions during the quarter.

Grande Prairie

Subsequent to the end of the first quarter, Trilogy announced that it has agreed to sell certain assets located in the Grande Prairie area of Alberta for cash consideration of $50 Million (before customary adjustments). The transaction is conditional upon the purchaser’s receipt of the Alberta Energy Regulator (“AER”) approvals for the transfer of the wells, pipelines and facilities. The assets being sold consist of approximately 44,427 net acres of mineral rights (including approximately 11,500 net acres of Montney/Doig mineral rights) in the Valhalla area along with current net production of approximately 1,100 Boe/d (16 percent oil and natural gas liquids) net to Trilogy, estimated Total Proved Developed Producing reserves of approximately 1,800 MBoe and Total Proved plus Probable reserves of approximately 5,500 MBoe, each as at December 31, 2016, net of Q1 2017 production.

The sale is effective May 1, 2017 and is expected to be completed before the end of May 2017, provided the purchaser receives the above mentioned AER approvals. Proceeds from the sale will be applied to reduce Trilogy’s indebtedness under its revolving credit facility.

Montney Oil Pool

The shift from hydrocarbon-based to water-based fracture stimulations in early 2016 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 recent wells. In addition, completion pump rates have increased substantially, resulting in increased fracture complexity. All of these factors combined have contributed to higher initial well productivity as compared to the Company’s first generation Montney oil wells.

Trilogy has allocated approximately $60 million towards further development of its Montney oil pool in 2017. The majority of the capital will be allocated to drill 15 wells and complete 18 wells in the pool, incorporating the efficiencies from the Company’s 2016 Montney drilling and completion program. To date, 6 wells have been drilled in the first quarter with plans to drill at least 9 additional horizontal wells through the second half of 2017. Trilogy also intends to allocate capital to a water disposal project, an enhanced recovery gas reinjection pilot project and to the construction of pad sites and pipelines intended for future development of the pool.

The following table updates production results to April 30, 2017 for the 9 horizontal Montney oil wells that were drilled, completed and brought on production in 2016, the 3 wells that were drilled in 2016 and completed in the first quarter of 2017. The variable results reflect the evolution of completion techniques described above and the amount of time the wells have been on production.

	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	293	399	1.1	582	20	22	1577	267	Mar 18/16
02/12-6-64-18W5	80	270	246	0.8	384	10	22	1566	326	May 12/16
10-31-64-18W5	48	251	253	1.3	473	20	28	2680	190	Sep 23/16
02/1-1-64-19W5	76	152	473	0.9	630	20	21	1498	161	Oct 16/16
02/2-1-64-19W5	82	95	541	0.6	646	20	21	1455	151	Oct 17/16
2-1-64-19W5	45	52	329	0.4	394	20	26	1525	136	Oct 20/16
02/4-6-64-18W5	70	105	530	0.8	661	20	32	1584	133	Nov 11/16
02/5-6-64-18W5	95	218	671	1.5	927	13.5	33	1573	142	Nov 12/16
03/4-6-64-18W5	69	133	515	1.0	682	20	32	1581	133	Nov 14/16
14-31-64-18W5	1	1	20	0.02	24	19.3	33	2787	61	Jan 19/17
13-31-64-18W5	22	44	374	0.8	502	17.4	27	2283	58	Jan 18/17
02/13-31-64-18W5	13	30	209	0.5	287	17.8	36	2938	64	Jan 16/17

Presley Montney Gas Development

Trilogy’s 2017 budget provided approximately $30 million to develop 6 (6.0 net) wells in the Presley Montney liquids-rich gas pool. Trilogy drilled 3 (3.0 net) extended length horizontal wells (each approximately 2 miles in lateral length) into the pool in the first quarter and is currently drilling a 3-well pad (1 mile laterals) through the second quarter. One of the extended reach lateral wells was fracture stimulated in April and is expected to be on production in early May. The remaining 2 wells are expected to be completed in mid-May and on production in mid-June once break up is over. The 3-well pad currently being drilled is expected to be completed and tied in during the third quarter. Trilogy plans to continue to prepare drilling locations and evaluate infrastructure alternatives for the Montney gas pool as well as operated Duvernay production in the Presley area, so as to be prepared for full field development when commodity prices increase.

Duvernay Update

Trilogy did not have any Duvernay spending in the first quarter but is preparing to build on the success of the Company’s recent wells and will be monitoring industry drilling, completion and production results adjacent to its Duvernay acreage. The 2 horizontal Duvernay wells Trilogy drilled in 2016 were drilled and completed on single well pads at a cost of approximately $10.2 million per well. Trilogy expects to realize significant reduction in costs relative to previous Duvernay wells once multi-well pad development begins. The following table summarizes the production up to April 30, 2017 from the 2 Duvernay horizontal wells drilled in 2016.

	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	30	427	204	2.9	686	70	2.2	147	Nov 10/16
12-21-63-17W5	38	72	334	0.6	439	533	2.2	115	Dec 21/16

Trilogy has allocated approximately $35 million towards Duvernay projects in the second half of 2017. The decision to execute this portion of the capital budget will be made later in the year.

Trilogy may consider monetizing a portion of its Duvernay acreage to help fund the development of the remaining Duvernay acreage. This could potentially include a joint venture arrangement, external sources of funding to accelerate the commercial development of some of this acreage or a sale of a portion of the Company’s Duvernay acreage. Trilogy has processing capacity in place to produce volumes from its Duvernay development plan for the initial two to three year development period; however, to produce Trilogy’s longer term Duvernay development plan, Trilogy will require access to additional operated and non-operated natural gas processing and NGL handling infrastructure.

Outlook

Trilogy plans to execute a 2017 capital spending budget that is within anticipated 2017 funds flow from operations based on Trilogy’s 2017 production expectations and forecasted pricing for the year. The level of capital spending in the second half of the year will depend on commodity prices and will primarily impact the Duvernay projects later in 2017.

Given the encouraging production results to date, which is expected to offset the impact of the aforementioned Grande Prairie disposition, Trilogy continues to reaffirm its 2017 annual guidance as follows:

Average production: 24,000 Boe/d (~35% oil and NGLs)

Average operating costs: $8.50/Boe

Capital expenditures: $130 Million

Additional Information

Trilogy’s financial and operating results for the first quarter of 2017, including Management’s Discussion and Analysis and the Company’s Unaudited Interim Consolidated Financial Statements and related Notes as at and for the quarter-ended March 31, 2017 can be obtained at http://media3.marketwire.com/docs/Q1-2017REPORT.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”, “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, restoration, and remediation 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 excluding assets and liabilities held for sale therein 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:

the anticipated closing of the previously announced transaction to sell certain assets in the Grande Prairie area, the timing thereof, the intended use of proceeds therefrom and the anticipated impact of the disposition on the Company’s capacity under its revolving credit facility as well as its production levels;
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 and the relative content of natural gas liquids therein;
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 operational efficiencies and cost cutting measures;
the capacity under and potential liabilities relating to processing and natural gas liquids handling arrangements as well as 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:

the likelihood that the previously announced Grande Prairie asset sale will close as planned;
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:

the risk that the purchaser of the Company’s Grande Prairie assets will not obtain the required approvals from the Alberta Energy Regulator in order to close the transaction by the end of May or at all;
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 NGL 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 Q1 2017, the ratio between Trilogy’s average realized oil price and the average realized natural gas price was approximately 20:1 (“Value Ratio”). The Value Ratio is obtained using the Q1 2017 average realized oil price of $61.36 (CAD$/Bbl) and the Q1 2017 average realized natural gas price of $3.09 (CAD$/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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