CALGARY, Alberta, March 12, 2019 (GLOBE NEWSWIRE) -- Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2018, as well as its year-end reserve evaluation as prepared by its qualified independent reserve evaluator. The Company’s Consolidated Financial Statements and Management’s Discussion and Analysis are available at www.cequence-energy.com and on SEDAR at www.sedar.com.

2018 Highlights

• Achieved full year 2018 production of 6,507 boe/d and increased liquids weighting to 23% up from 17% in 2017;
• Funds flow from operations in 2018 was $13.1 million or $0.53 per share based on year end 2018 outstanding shares;
• Fourth quarter 2018 oil production increased by 160% over the same period in 2017;
• Strengthened the Company’s balance sheet through a $8.6 million rights offering and renegotiation of the $60 million term debt with a 4 year maturity and 5% interest rate;
• Continued successful step out drilling of the Company’s Dunvegan oil pool.  Drilled, completed, and tied in 5 gross (4 net) horizontal Dunvegan oil wells and 1 gross (1 net) successful stratigraphic oil well test;
• Corporate 10% proved developed producing reserve value of $74 million includes a $20.6 million unutilized take or pay short fall under this scenario.  Additional Cequence production volumes from the total proved and proved plus probable cases would alleviate this shortfall;
• The Corporate net asset value per share at a 10% discount rate using GLJ January 1, 2019 prices and year end 2018 net debt is $4.31/share total proved and $15.19/share proved plus probable;
• Achieved a Corporate proved plus probable FD&A of $3.50/boe;
• Before production, Dunvegan oil proved developed producing, total proved, and proved plus probable reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe, 2.9 MMboe and 5.3 MMboe;
• Dunvegan oil total proven and proven plus probable net present values at 10% discount rate are $41.8 million and $74.7 million respectively using GLJ January 1, 2019 prices; and
• Added market diversity away from AECO prices with 10,850 GJ/d of production sold at Dawn beginning April 1, 2018. Realized gas price in 2018 was $2.40/mcf, an increase of 58% over the AECO 2018 spot price of $1.52/mcf.

Comparative financial and operating information for 2018 and 2017 are as follows:

(000’s except per share and per unit amounts)	Three months ended December 31,						Twelve months ended December 31,
	2018		2017		% Change		2018		2017		% Change
FINANCIAL
Total revenue(1), (5)	12,184		13,585		(10	)	58,921		65,836		(11	)
Comprehensive loss	(3,802	)	(6,638	)	(43	)	(9,699	)	(99,362	)	(90	)
Per share – basic and diluted (6)	(0.16	)	(0.54	)	(70	)	(0.61	)	(8.09	)	(92	)
Funds flow from operations (2), (5)	2,071		1,583		31		13,087		19,329		(32	)
Per share, basic and diluted (6), (7)	0.08		0.13		(38	)	0.82		1.57		(48	)
Capital expenditures, before acquisitions (dispositions)	13,397		5,593		140		23,800		25,857		(8	)
Capital expenditures, including acquisitions (dispositions)	12,463		1,316		847		20,937		21,580		(3	)
Net debt (3), (5)	(72,103	)	(68,501	)	5		(72,103	)	(68,501	)	5
Weighted average shares outstanding – basic (6)	24,553		12,277		100		15,942		12,277		30
Weighted average shares outstanding – diluted (6)	24,553		12,277		100		15,942		12,277		30
Common shares outstanding – end of period	24,553		12,277		100		24,553		12,277		100
OPERATING
Production volumes
Natural gas (Mcf/d)	27,645		33,331		(17	)	30,098		40,466		(26	)
Crude oil (bbls/d)	736		283		160		763		344		122
Natural gas liquids (bbls/d)	227		257		(12	)	250		254		(2	)
Condensate (bbls/d)	427		617		(31	)	478		797		(40	)
Total (boe/d)	5,997		6,713		(11	)	6,507		8,139		(20	)
Sales prices
Natural gas, including realized hedges ($/Mcf)	2.91		2.33		25		2.49		2.53		(2	)
Crude oil and condensate, including realized hedges ($/bbl)	37.74		66.73		(43	)	61.89		61.44		1
Natural gas liquids ($/bbl)	35.37		38.55		(8	)	38.18		30.72		24
Total ($/boe)	22.08		22.00		1		24.81		22.16		12
Netback ($/boe)
Price, including realized hedges	22.08		22.00		1		24.81		22.16		12
Royalties	(1.33	)	(0.63	)	111		(1.67	)	(1.06	)	58
Transportation	(3.84	)	(1.66	)	131		(3.01	)	(1.88	)	60
Operating costs	(9.86	)	(12.91	)	(24	)	(10.14	)	(9.29	)	9
Operating netback (5)	7.05		6.80		4		9.99		9.93		1
General and administrative	(2.07	)	(1.88	)	10		(2.22	)	(1.48	)	50
Interest (4)	(1.42	)	(2.46	)	(42	)	(1.98	)	(2.07	)	(4	)
Cash netback (5)	3.56		2.46		45		5.79		6.38		(9	)

1. Total revenue is presented gross of royalties and includes realized gains (loss) on commodity contracts.
2. Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital.
3. Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the principal value of the Senior Notes and Term Loan (as such terms are defined below).
4. Represents finance costs less refinancing expenses, amortization on transaction costs, accretion expense on Senior Notes and provisions.
5. Refer to “Non-GAAP Measures” advisory in this press release.
6. On October 22, 2018, the Company’s shareholders approved a share consolidation based on one new common share for every 20 pre-consolidation shares. All information relating to issued and common shares, stock options, warrants, restricted share units and per share amounts, have been restated to reflect the share consolidation for all periods presented.
7. Funds flow per share calculated as if the ending 24,553,000 common shares at December 31, 2018 were outstanding for the entire period would be $0.53 per share for the twelve months ended December 31, 2018.

Financial

Natural gas prices remained low in both 2018 and 2017 with AECO prices averaging $1.52/mcf and $2.23/mcf, respectively. Annual funds flow from operations decreased 32% to $13.1 million mainly due to lower natural gas prices and volumes. The decrease was partially offset by increased crude oil, condensate and NGL prices and oil volumes year over year. Fourth quarter funds flow increased 31% to $2.1 million, mainly due to increased production revenue, lower operating expenses and lower interest expense on the Term Loan. For the twelve months ended December 31, 2018, the Company recorded a comprehensive loss of $9.7 million compared to $99.3 million in 2017. The decrease is due to impairments of $96.2 million in the second quarter of 2017 as a result of a lower outlook for crude oil and natural gas prices.

Capital expenditures for the year were $23.8 million ($20.9 net of dispositions) with $19.9 million focused on wells with higher oil and liquids content. The majority of capital was spent as follows: $16.3 million on drilling and completion activity, $4.8 million on facilities and equipment, and $1.0 million on workovers.

On July 27, 2018 Cequence announced a series of transactions to refinance the Company’s balance sheet and provide greater flexibility and liquidity to execute the ongoing business plan of the Company. Cequence entered into a second lien secured loan agreement for a $60 million term loan facility due October 3, 2022 (the “Term Loan”) to refinance the existing $60 million unsecured five year senior notes which were due on October 3, 2018 (the “Senior Notes”). At the same time, Cequence launched a rights offering for holders of its common shares as of August 9, 2018 to subscribe for 12,276,394 (post-consolidation) flow through common shares of the Company for gross proceeds of up to $8.6 million. The rights offering was fully subscribed for and closed on September 13, 2018.

The Company has $72.1 million in net debt as at December 31, 2018, which is comprised of the Term Loan ($60 million) and a working capital deficiency of $12.1 million (excluding commodity contracts). The Company also has a senior credit facility of $7 million that remains undrawn other than letters of credit of $1.6 million and has a maturity date May 31, 2019.  

The Company has hedged approximately 26% of its 2019 estimated production, including 40% of its forecasted oil volumes, at a price of $85.29/bbl CAD. Since April 1, 2018 the Company has been selling 10,850 GJ/d of gas production in the Dawn market. The Dawn marketing arrangement has provided the Company diversification away from the volatile AECO prices for approximately 1/3 of its gas production. For the year ended December 31, 2018, Dawn prices averaged approximately $4.15/mcf compared to AECO pricing of approximately $1.52/mcf.

2018 Operational and Production

During the winter of 2017/2018 and the fourth quarter of 2018, Cequence drilled, completed, and brought on stream 5 gross (4 net) horizontal Dunvegan oil wells as well as drilled 1 gross (1 net) vertical stratigraphic oil test well. The horizontal wells drilled in the fourth quarter of 2018 were tied into permanent facilities on January 10, 2019. In February 2019, the pumps were removed from the two wells and they are both flowing. The recent production from the fourth quarter 2018 wells are shown in the table below.

			January 2019 calendar day average (gross)		Last 10/24 Operating days February (gross)
Well UWI	CQE %		Oil (bbl/d)	Gas (mcf/d)	Oil (bbl/d)	Gas (mcf/d)
10-04-062-26W5	100	%	266	650	310	1,300
16-02-062-26W5	100	%	225	370	260	1,000

In 2018, approximately $19.9 million dollars or 84% of the Corporation’s $23.8 million capital expenditures, before acquisitions, was spent on the Dunvegan oil program. This Dunvegan capital included $6.4 million for drilling, $9.5 million on completions, and $4.0 million on facilities and equipment including the installation of an 8 inch gathering line to the new 2018 multi-well pad site as well as an upgrade to the 5-7-62-25W5 oil handling facility to eliminate long term rental equipment. A majority of the remaining 2018 capital spend was focused on expanding and optimizing water disposal capacity in the Simonette area.

For the year ended December 31, 2018, operating costs averaged $10.14/boe in 2018, up 9% from 2017, with operating costs down 24% in the fourth quarter to $9.86/boe as compared to the same period of 2017. In the second half of 2017 and extending into the first quarter of 2018, the Company had one-time expenses associated with accelerating a water handling and disposal project to reduce its surface water and associated costs at the Simonette field. In the fourth quarter of 2018, a second water disposal well and associated equipment was added in the east side of Simonette which has further reduced water trucking and disposal costs. Despite lower forecasted 2019 total production rates the 2019 operating costs are expected to remain between $9.50 and $10.50 per boe. 

Corporate production for the three and twelve months ended December 31, 2018 averaged 5,997 boe/d and 6,507 boe/d, respectively, compared to production of 6,713 boe/d and 8,139 boe/d in 2017. Oil and liquids production for the same periods increased to 1,390 bbl/d and 1,491 bbl/d, up 20% and 7% respectively. 

2018 Independent Reserve Evaluation Matters

GLJ Petroleum Consultants (“GLJ”) prepared the reserves report effective December 31, 2018 (the "GLJ Report") for the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence. The GLJ Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The reserves data provided in this press release represents only a portion of the disclosure required by NI 51-101. Additional information from the GLJ Report, including all disclosure required under NI 51-101, will be contained in the Company’s Annual Information Form for the year ended December 31, 2018, which will be filed on SEDAR on or before March 31, 2019. Reserves highlights of the Company include:

• Corporate reserves were 10.6 MMboe proved developed producing, 57.0 MMboe proven, and 129.4 MMboe on a proved plus probable basis.
• Corporate FD&A, including changes in future development capital, was $3.50/boe on a proven plus probable basis;
• The Corporate net asset value per share at a 10% discount rate using GLJ January 1, 2019 prices and year end 2018 net debt is $4.31/share total proved and $15.19/share proved plus probable;
• Before production, Dunvegan oil proved developed producing, total proved, and proved plus probable reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe, 2.9 MMboe and 5.3 MMboe. 
• Dunvegan oil total proven and proven plus probable net present values at 10% discount rate are $41.8 million and $74.7 million respectively using GLJ January 1, 2019 prices
• Undeveloped Dunvegan oil inventory is 5.5 net proven and 10.5 net proved plus probable locations. 
• The Dunvegan oil program finding, development, and acquisition costs inclusive of changes in booked future development capital, was $12.64/boe proved developed producing, $20.77/boe total proved, and $14.91/boe proved plus probable. The 2018 operating netback for the Dunvegan oil area is estimated at $34.74/boe which yields recycle ratios of 2.7, 1.7, and 2.3 respectively.
• Due to lower commodity prices and other economic factors non-core assets totaling 1.4 MMboe proved and 2.3 MMboe proven plus probable were not assigned reserves. 
• A total of 0.31 MMboe proven and 0.51 MMboe proven plus probable reserves were sold in calendar year 2018.

The tables below are a summary of the oil, NGL and natural gas reserves attributable to the properties of Cequence and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Report based on forecast price and cost assumptions. The calculated NPVs include a deduction for estimated future well abandonment and reclamation costs. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of Cequence's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Summary of Oil, Natural Gas and NGL Reserves

		Light and Medium Crude Oil				Tight Oil				Conventional Natural Gas				Shale Gas				NGL				Total Oil Equivalent
Reserves Category		Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)
		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		MMcf		MMcf		(Mbbl)		(Mbbl)		(MBOE)		(MBOE)
Proved
Developed Producing		735		615		0		0		18,615		16,961		33,153		28,325		1,259		826		10,623		8,989
Developed Non-Producing		12		9		0		0		2,569		2,267		4,328		3,569		146		90		1,307		1,072
Undeveloped		649		564		0		0		3,688		3,369		223,813		194,944		6,541		5,485		45,107		39,101
Total Proved		1,396		1,187		0		0		24,872		22,596		261,293		226,838		7,946		6,402		57,036		49,161
Probable		1,193		965		0		0		58,926		54,068		311,007		259,564		9,524		7,070		72,372		60,306
Total Proved plus Probable		2,589		2,152		1		0		83,799		76,665		572,300		486,402		17,470		13,471		129,409		109,468

Notes:

1. Columns may not add due to rounding.
2. "Gross" reserves means the Company's working interest (operated and non‐operated) share before deduction of royalties payable to others and without including any royalty interests of the Company.
3. "Net" reserves means the Company's working interest (operated and non‐operated) share after deduction of royalty obligations plus the Company's royalty interests in reserves.

Summary of Net Present Value of Future Net Revenue



Reserves Category		Before Future Income Tax Expenses Discounted at (%/year)
		0		5		10		15		20		10
		(M$)		(M$)		(M$)		(M$)		(M$)		($/mcfe)
Proved
Developed Producing		90,358		81,708		74,036		67,593		62,231		1.37
Developed Non-Producing		11,110		8,846		7,134		5,855		4,889		1.11
Undeveloped		311,475		175,301		96,640		49,580		20,458		0.41
Total Proved		412,943		265,855		177,810		123,028		87,577		0.6
Probable		875,166		460,970		267,145		166,182		108,799		0.74
Total Proved plus Probable		1,288,109		726,824		444,955		289,210		196,377		0.68

Reserves Category		After Future Income Tax Expenses Discounted at (%/year)
		0		5		10		15		20
		(M$)		(M$)		(M$)		(M$)		(M$)
Proved
Developed Producing		90,358		81,708		74,036		67,593		62,231
Developed Non-Producing		11,110		8,846		7,134		5,855		4,889
Undeveloped		311,475		175,301		96,640		49,580		20,458
Total Proved		412,943		265,855		177,810		123,028		87,577
Probable		678,622		369,651		220,181		140,117		93,468
Total Proved plus Probable		1,091,566		635,505		397,991		263,145		181,046

Notes:

1. Columns may not add due to rounding.
2. It should not be assumed that the undiscounted and discounted future net revenues estimated by GLJ represent the fair market value of the reserves.

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of January 1, 2019 in the GLJ Report in estimating Cequence's reserves data using forecast prices and costs: 

		Natural Gas				Light Crude Oil				Pentanes Plus
		Henry Hub		AECO Gas Price		WTI		Edmonton		Edmonton		Inflation Rates		Exchange Rate
Year		($US/MMBtu)		($Cdn/MMBtu)		($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		%/year		($US/$Cdn)
Forecast
2019		3		1.85		56.25		63.33		67.67		2		0.75
2020		3.15		2.29		63		75.32		79.22		2		0.77
2021		3.35		2.67		67		79.75		83.54		2		0.79
2022		3.5		2.9		70		81.48		85.49		2		0.81
2023		3.63		3.14		72.5		83.54		87.8		2		0.82
2024		3.7		3.23		75		86.06		90.3		2		0.825
2025		3.77		3.34		77.5		89.09		93.33		2		0.825
2026		3.85		3.41		80.41		92.62		96.86		2		0.825
2027		3.93		3.48		82.02		94.57		98.81		2		0.825
2028		4		3.54		83.66		96.56		100.8		2		0.825
Thereafter escalation rate of 2%

The following table summarizes the elements of future net revenue attributable to reserves estimated using forecast prices and costs.

	Revenue ($000s)		Royalties ($000s)		Operating Costs ($000s)		Development Costs ($000s)		Abandonment and Reclamation Costs ($000s)		Future Net Revenue Before Income Taxes ($000s)		Income Taxes ($000s)		Future Net Revenue After Income Taxes ($000s)
Proved Reserves	1,611,942		111,793		601,968		462,720		22,518		412,943		-		412,943
Proved Plus Probable Reserves	3,890,561		324,825		1,379,871		859,026		38,729		1,288,109		196,543		1,091,566

Future Net Revenue by Product Type

Reserves Category		Product Type		Future Net Revenue Before Income Taxes (3) (discounted at 10% per year) ($000s)		Unit Value $/boe		Unit Value $/MMcf
Proved Reserves		Light and Medium Oil (1)		37,336		14.64		2.44
		Tight Oil (1)		7		15.83		2.64
		Conventional Natural Gas (2)		11,041		4.17		0.70
		Shale Natural Gas		129,426		2.94		0.49
		Total		177,810		3.62		0.60
Proved Plus Probable Reserves		Light and Medium Oil (1)		70,019		15.23		2.54
		Tight Oil (1)		12		17.91		2.98
		Conventional Natural Gas (2)		28,028		2.45		0.41
		Shale Natural Gas		346,896		3.71		0.62
		Total		444,955		4.06		0.68

Notes:

1. Includes solution gas and other by-products
2. Including by-products but excluding solution gas
3. Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups.  Unit values are based on Company Net Reserves.

Dunvegan Oil: Company Interest Reserves Reconciliation

			Proved Producing			Total Proved			Total Proved Plus Probable
Technical Revisions			85.7			72.9			246.1
Drilling Extensions			1,493.1			1,378.6			2,493.5
Change in Finding and Development Costs ($M)		$	0		$	10,192		$	20,890
2018 Capital		$	19,961		$	19,961		$	19,961
F&D ($/boe)(1)		$	12.64		$	20.77		$	14.91
2018 Netback ($/boe) (1)		$	34.74		$	34.74		$	34.74
Recycle Ratio(1)			2.7			1.7			2.3

Notes:

1.  See “Non-GAAP Measures” in this press release.

Board of Directors and Management Update

Daryl Gilbert has announced his resignation from the Company’s board, effective the end of the day today, March 12, 2019. Mr. Gilbert has served on the Company’s board since 2012, and Cequence and the rest of the board thank Mr. Gilbert for his years of dedicated service to the Company and his contribution to helping the Company navigate a difficult commodity price environment.

Cequence is pleased to announce that Dan O’Neil has been appointed to the Company’s board effective today. Mr. O’Neil is a professional engineer with over 30 years of experience in the Canadian oil and gas business, including senior management positions with EnCana Corporation and later serving as the Chief Executive Officer of Surge Energy Inc. until May 2013. Mr. O’Neil was also one of the founders of Breaker Energy Ltd., which was acquired by NAL Energy Corporation (formerly NAL Oil & Gas Trust)

As previously announced on February 12, 2019 Allan Mowbray will be joining Cequence as Chief Financial Officer effective March 15, 2019. In connection Mr. Mowbray joining the Company, Howard Crone has, effective today, resigned from his position as Executive Vice President of the Company. Mr. Crone will continue to serve as a director of Cequence. Also effective today, Donald Archibald’s title will change from Executive Chairman to Chairman.

2019 Guidance:

The Company’s guidance for the year ended December 31, 2019 includes the results of the fourth quarter 2018 oil wells, the restructured $60 million Term Loan (with its 5% interest rate), and an additional planned 2 gross (2 net) Dunvegan oil wells drilled and on production at the end of the third quarter of 2019. Cequence will continue to monitor volatility in commodity prices with the focus that 2019 capital activity will remain within funds flow from operations. 

(000’s, except per share and per unit references)	Guidance year ended December 31, 2019
Average production, BOE/d (1)	5,800
Funds flow from operations ($)(2)	17,000
Funds flow from operations per share(2)	0.69
Exploration and development expenditures ($)	13,000
Net wells	2.0
Operating and transportation costs ($/boe)	15.00
G&A costs ($/boe)	2.30
Royalties (% revenue)	10
Crude – WTI (US$/bbl)	57.50
Natural gas – AECO (CDN$/GJ)	1.69
Period end, net debt ($) (3)	69,000
Common shares outstanding end of period	24,553

⁽¹⁾ Average production estimates on a per BOE basis are comprised of 72% natural gas and 28% oil and natural gas liquids in 2019.
⁽²⁾ Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. See “Non-GAAP Measures” in this press release.
⁽³⁾ Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the aggregate principal amount of the term loan.

About Cequence

Cequence is a publicly traded Canadian energy company involved in the acquisition, exploitation, exploration, development and production of natural gas and crude oil in western Canada. Further information about Cequence may be found in its continuous disclosure documents filed with Canadian securities regulators at www.sedar.com.

For further information contact:

Todd Brown, Chief Executive Officer, (403) 806-4049, tbrown@cequence-energy.com
Allan Mowbray, Chief Financial Officer, (403) 806-4041, amowbray@cequence-energy.com

Forward-looking Statements or Information

Certain statements included in this press release constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as "believe", "expect", "plan", "estimate", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this press release may include, but are not limited to, statements or information with respect to: the Company’s guidance and forecasts for the year ended December 31, 2019 and its expectations regarding market access for the Company’s natural gas production; reserves quantities and discounted net present value of future net cash flow from such reserves; future drilling and capital expenditure expectations; expected netbacks to be derived from hedging activities; future water handling costs and operating costs. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company 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 the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

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 the Company and described in the forward-looking statements or information. These risks and uncertainties may cause actual results to differ materially from the forward-looking statements or information. The material risk factors affecting the Company and its business are contained in the Company's Annual Information Form which is available on SEDAR at www.sedar.com.

The forward-looking statements or information contained in this press release are made as of the date hereof and the Company 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 required by applicable securities laws. The forward-looking statements or information contained in this press release are expressly qualified by this cautionary statement.

Additional Advisories

Non-GAAP Measures

This press release contains references to terms and financial measures commonly used in the oil and gas industry but that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) in Canada and are therefore unlikely to be comparable to similar measures presented by other companies. Such terms and financial measures are referred to as “Non-GAAP Measures”. The Non-GAAP Measures used in this press release are described below. Non-GAAP Measures should not be used to make comparisons between companies, including Cequence.

Total revenue is a Non-GAAP Measure that represents production revenue gross of royalties and including realized gain (loss) on commodity contracts. Management utilizes this measure to analyze revenue and commodity pricing and its impact on operating performance.

Funds flow from operations is a Non-GAAP Measure that represents cash flow from operating activities before adjustments for decommissioning liability expenditures, proceeds from the sale of commodity contracts and changes in non-cash working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income (loss) per share.

Operating and cash netback are Non-GAAP Measures. Operating netback equals total revenue less royalties, operating costs and transportation costs. Cash netback equals the operating netback less general and administrative expenses and interest expense. Management utilizes these measures to analyze operating performance. 

Net debt is a Non-GAAP Measure that is calculated as working capital deficiency (excluding commodity contracts) plus the principal value of the Term Loan (previously the Senior Notes) which reflects the estimated amount that will be repaid upon maturity. Cequence uses net debt as it provides an estimate of the Company’s assets and obligations expected to be settled in cash.

Finding and Development (“F&D”) costs and Finding, Development and Acquisition (“FD&A”) costs . have been calculated in accordance with NI 51-101. F&D costs are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs includes all current year net capital expenditures, excluding property acquisitions and dispositions with associated reserves, including changes in future development capital (“FDC”) on a proved or proved plus probable basis. FD&A costs are calculated by dividing the sum of the total capital expenditures for the year including both costs and associated reserve additions related to acquisitions net of any dispositions during the year, by the change in reserves within the applicable reserves category. Further information on how the Company calculates F&D and FD&A costs is available in the Company's Annual Information Form filed on SEDAR. Management uses F&D costs and FD&A costs as a measure to assess the performance of the Company's resources required to locate and extract new hydrocarbon reservoirs, including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. F&D and FD&A costs used by Cequence may not be comparable to similar measures used by other issuers.

Recycle ratio is measured by dividing the operating netback by appropriate F&D or FD&A costs per boe for the year. Operating netback is calculated using production revenues, including realized gains and losses on commodity hedging, less royalties, transportation and operating expenditures, calculated on a per boe equivalent basis. Reserve replacement ratio measures the amount of reserves added to a Company`s reserve base during the year relative to the amount of oil and gas produced. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time.

Oil & Gas Disclosure Advisories

This press release contains estimates of the net present value of the Company's future net revenue from its reserves. Such amounts do not represent the market value of the Company's reserves.

BOEs are presented on the basis of one BOE for six Mcf of natural gas. Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

For fiscal 2018 the ratio between the average price of West Texas Intermediate (“WTI”) crude oil at Cushing and NYMEX natural gas was approximately 20:1 (“Value Ratio”). The Value Ratio is obtained using the 2018 WTI average price of $65.20 (US$/Bbl) for crude oil and the 2018 NYMEX average price of $3.20 (US$/MMbtu) for natural gas. 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.

The Company’s estimate that it has 50 net Montney locations on its West Simonette lands. Including in the 50 locations are 26 locations included in the GLJ report and 24 additional wells identified by management to be prospective. The Company identifies 24 net Dunvegan oil wells prospective on its land. There are 8 wells identified in the GLJ report and the remainder are based on internal estimates. Unbooked locations do not do not have attributed reserves and there is no certainty that if these locations would result in additional oil and gas reserves or production.

The TSX has neither approved nor disapproved the contents of this news release.

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