CALGARY, Alberta, March 10, 2020 (GLOBE NEWSWIRE) -- Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce its operating and financial results for the three and twelve months ended December 31, 2019. The Company’s Management’s Discussion and Analysis (“MD&A”) and Consolidated Financial Statements are available at cequence-energy.com and on SEDAR at www.sedar.com.

HIGHLIGHTS

• Production was 5,892 boe/d, 25% of which was comprised of crude oil and liquids for the three months ended December 31, 2019 compared to 5,997 boe/d, 23% of which was comprised of crude oil and liquids for the same period in 2018.
• The Company entered into a farm-in agreement in December 2019 committing to equip and operate two shut-in Montney oil wells in Simonette in exchange for a 50% interest in 5 net sections (10 gross) of Montney land surrounding the two wells. February 2020 gross production per calendar day for the two wells was approximately 570 bbls/d of oil and 1,150 mcf/d of natural gas.
• Capital expenditures for the three months ended December 31, 2019 were $1.9 million to complete natural gas lift optimization projects in Simonette started in the third quarter 2019.

SELECTED INFORMATION

(in thousands of dollars except production volumes, per share and $/boe amounts)	Three months ended December 31,						Twelve months ended December 31,
		2019			2018			2019				2018
Financial
Total revenue(1)	$	14,859		$	12,184		$	55,479			$	58,921
Net loss and comprehensive loss		(1,733	)		(3,802	)		(13,002		)		(9,699	)
Per share – basic and diluted		(0.04	)		(0.16	)		(0.39		)		(0.61	)
Funds flow from operations(1)		4,254			2,071			11,844				13,087
Per share - basic and diluted		0.10			0.08			0.35				0.82
Capital expenditures, before acquisitions (dispositions)		1,941			13,397			8,920				23,800
Total assets								267,662				283,640
Net debt(1)								54,778				62,523
Production volumes
Natural gas (Mcf/d)		26,549			27,645			26,658				30,098
Crude oil (bbls/d)		527			736			679				763
Natural gas liquids (bbls/d)		353			227			230				250
Condensate (bbls/d)		587			427			455				478
Total (boe/d)		5,892			5,997			5,807				6,507
Netback ($/boe)
Price, including realized hedges	$	27.41		$	22.08		$	26.18			$	24.81
Operating netback(1)	$	11.49		$	7.05		$	9.50			$	9.99

¹ Refer to “Non-IFRS Measures” in this press release for further information.

For the twelve months ended December 31, 2019 funds flow from operations was $11.8 million, $1.2 million lower than the same prior year period. The decrease was due to production declines and higher transportation expenses partially offset by higher realized natural gas and crude oil prices and lower finance expenses. Production was 5,807 boe/d, 23% of which was comprised of crude oil and liquids for the twelve months ended December 31, 2019 compared to 6,507 boe/d, 23% of which was comprised of crude oil and liquids for the same period in 2018.

Benchmark pricing

	Three months ended December 31,				Twelve months ended December 31,
Benchmark pricing		2019		2018		2019			2018
AECO-C spot gas (CDN$/Mcf)	$	2.48	$	1.58	$	1.76		$	1.52
Ontario Dawn gas (CDN$/Mcf)		2.95		5.74		3.19			4.15
WTI crude oil (US$/bbl)		56.96		60.70		57.03			65.20
Edmonton City Gate oil (CDN$/bbl)		67.99		44.14		69.05			68.89
US$/CDN$ exchange rate		0.76		0.75		0.75			0.77

Volatile and weak natural gas prices remain below thresholds where investment in natural gas wells is economically beneficial. AECO prices averaged $2.48/Mcf for the three months ended December 31, 2019 compared to $1.58/Mcf for the same prior year period. Oil prices were also volatile and lower in the fourth quarter 2019, compared with the same prior year period as increased U.S. supply, trade tensions between the U.S. and China and concerns of a slowing global economy limited demand growth creating an uncertain pricing environment.

OPERATIONS

	Three months ended December 31,
	2019					2018
	($ thousands)			($/boe)		($ thousands)			($/boe)
Sales of natural gas, crude oil and condensate	$	14,551		$	26.84	$	12,591		$	22.82
Realized gain (loss) on commodity contracts	308				0.57		(407	)		(0.74	)
Total revenue(1)		14,859			27.41		12,184			22.08
Royalties expense		1,051			1.94		736			1.33
		13,808			25.47		11,448			20.75
Operating expense		5,177			9.55		5,440			9.86
Transportation expense		2,401			4.43		2,116			3.84
Operating netback(1)		6,230			11.49		3,892			7.05
General and administrative expense		1,349			2.49		1,143			2.07
Finance expense		862			1.59		975			1.77
Cash netback(1)		4,019		$	7.41		1,774		$	3.21
Unrealized loss (gain) on derivative financial instruments		836					(4,309	)
Depletion and depreciation expense		4,854					11,322
Share-based payment expense		87					114
Other income		(25	)				(1,551	)
Net loss and comprehensive loss	$	(1,733	)			$	(3,802	)

¹ Refer to “Non-IFRS Measures” in this press release for further information.

Production for the three months ended December 31, 2019 averaged 5,892 boe/d compared to 5,997 boe/d for the same prior year period. The decrease was due to the natural decline of the natural gas wells and lower crude oil production due to natural decline of the 3.0 (2.0 net) Dunvegan horizontal oil wells that were completed in the first quarter 2018.  Crude oil and liquids production as a percentage of total production increased to 25 percent in the three months ended December 31, 2019 from 23 percent for the same prior year period.

Operating netback⁽¹⁾ was $11.49 per boe for the three months ended December 31, 2019 compared to $7.05 per boe for the same prior year period. The increase was due primarily to higher realized prices for crude oil and condensate partially offset by higher royalty and transportation expenses.

	Twelve months ended December 31,
	2019					2018
	($ thousands)			($/boe)		($ thousands)			($/boe)
Sales of natural gas, crude oil and condensate	$	53,066		$	25.04	$	60,196		$	25.34
Realized gain (loss) on commodity contracts	2,413				1.14		(1,275	)		(0.53	)
Total revenue(1)		55,479			26.18		58,921			24.81
Royalties expense		3,215			1.52		3,969			1.67
		52,264			24.66		54,952			23.14
Operating expense		22,786			10.75		24,080			10.14
Transportation expense		9,351			4.41		7,160			3.01
Operating netback(1)		20,127			9.50		23,712			9.99
General and administrative expense		5,532			2.61		5,267			2.22
Finance expense		3,655			1.72		7,874			3.32
Cash netback(1)		10,940		$	5.17		10,571		$	4.45
Unrealized loss (gain) on derivative financial instruments		3,523					(3,303	)
Depletion and depreciation expense		20,169					27,480
Share-based payment expense		432					300
Other income		(182	)				(4,207	)
Net loss and comprehensive loss	$	(13,002	)			$	(9,699	)

¹ Refer to “Non-IFRS Measures” in this press release for further information.

Production for the twelve months ended December 31, 2019 averaged 5,807 boe/d compared to production of 6,507 boe/d for the same prior year period. The decrease was due to natural decline of natural gas wells, shutting in approximately 3,000 Mcf/d of non-core natural gas production in Northeastern British Columbia from June to September 1^st, 2019 and non-core dispositions in 2018.

Operating netback⁽¹⁾ was $9.50 per boe for the twelve months ended December 31, 2019 compared to $9.99 per boe for the same prior year period. The decrease was primarily due to higher transportation expenses due to fixed transportation contracts for crude oil and natural gas entered into in 2018 and lower production increasing fixed costs per boe. Crude oil transportation costs prior to entering into the oil transport agreement were included as part of realized price on the crude oil sale whereby the costs offset price. The natural gas marketing arrangement provided diversification away from volatile AECO prices for approximately 40 percent of the Company’s gas production to the Dawn, Ontario market. The toll on the Empress to Dawn hub is contracted at a cost of U.S.$0.77 per GJ for a period of 10 years expiring in 2028 with an early termination right that can be exercised following the initial five years of service.

Operating expenses for the twelve months ended December 31, 2019 were $22.8 million or $10.75 per boe compared to $24.1 million or $10.14 per boe for the same prior year period. Lower water handling costs with the completion of a water disposal well in 2018, purchase of the water disposal line at Simonette in the third quarter 2019 and reduced long-term field rentals expenses were partially offset in 2019 by workover, swabbing and chemical expenses to optimize and reactivate production and facility turnaround costs. The increase in per boe operating costs was due to lower production.

Finance expenses for the twelve months ended December 31, 2019 were lower compared to the same prior year period due to fees to restructure the senior loan in 2018 replacing it with the Term Loan and reducing the interest rate on the debt from 9.7% to 5.0% as part of the restructuring.

Capital Expenditures

	Three months ended December 31,					Twelve months ended December 31,
(in thousands of dollars)		2019		2018			2019			2018
Land	$	296	$	213		$	898		$	739
Geological & geophysical and capitalized overhead		163		184			1,044			1,015
Drilling, completions and workovers		725		10,426			2,937			17,209
Equipment, facilities and tie-ins		757		2,573			4,026			4,836
Office furniture & equipment		-		1			15			1
Capital expenditures		1,941		13,397			8,920			23,800
Acquisitions		4		-			1,522			-
Dispositions (i)		-		(934	)		(39	)		(2,863	)
Total capital expenditures	$	1,945	$	12,463		$	10,403		$	20,937

(i) Represent the cash proceeds from the sale of assets.

Capital expenditures for the twelve months ended December 31, 2019 focused on Simonette. The Company completed and tied in the 2.0 gross (2.0 net) Dunvegan horizontal oil wells drilled in the fourth quarter of 2018 and has invested in enhancing and optimizing existing well performance using gas lift solutions.

The Company acquired a water disposal pipeline in the third quarter 2019 for $1.5 million. This allows the Company to operate and control the pipeline providing greater flexibility over water handling at Simonette and reducing future operating costs.

In December 2019 Cequence entered into a farm-in agreement and committed to equip and operate two shut-in Montney Oil wells in the Simonette area. In exchange the Company receives a majority interest in the wells until the capital invested is repaid. After payout the Company’s working interest reverts to 50% and Cequence will earn 5 net sections (10 gross) of Montney land surrounding the two wells. Both wells were brought back on to production in the first quarter 2020. February 2020 gross production per calendar day for the two wells was approximately 570 bbls/d of oil and 1,150 mcf/d of natural gas. The natural gas production is tied into Cequence’s gathering system and the oil and water are currently being trucked to facilities for processing and disposal.

Due to oil price volatility, COVID-19 and concerns of a global economic slowdown, the Company is reviewing its 2020 budget and will not be providing an outlook for 2020 at this time.

RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

Following the completion of the 2019 financial year, management determined that as at December 31, 2019 certain accrued liabilities related to operating expenses for periods prior to January 1, 2018 were overstated by an aggregate of $9.6 million. The Company has disclosed in Note 4 of the annual audited consolidated financial statements for the year ended December 31, 2019 the effect of this adjustment. The effects of the restatement on the consolidated statements of financial position as at December 31, 2018 and January 1, 2018 are as follows:

(in thousands of dollars)	December 31, 2018			January 1, 2018
Accounts payable and accrued liabilities – As originally reported	$	35,736		$	33,106
Accrual adjustment		(9,580	)		(9,580	)
Accounts payable and accrued liabilities – As restated	$	26,156		$	23,526
Deficit – As originally reported	$	(523,269	)	$	(513,570	)
Accrual adjustment		(9,580	)		(9,580	)
Deficit – As restated	$	(513,689	)	$	(503,990	)

Management has concluded that a material weakness in its internal controls over financial reporting existed as at December 31, 2019. The material weakness was caused by a failure to effectively operate an internal control to review and assess accrued liabilities related to operating expenses. The weakness and managements remediation plan are described in the “Internal Controls over Financial Reporting” section of the Company’s December 31, 2019 MD&A. 

RESERVES

GLJ Petroleum Consultants (“GLJ”), the Company’s independent, qualified reserves evaluator, prepared the Company’s reserves report effective December 31, 2019 (collectively referred to herein as the “GLJ Report”) for the crude oil, natural gas liquids (“NGL”) 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 of the Canadian Securities Administrators (“NI 51-101”).

The tables below are a summary of the crude 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 reserves attributable to the Company’s properties have been estimated assuming that development of each property in respect of which the estimate has been made will occur, regardless of the likely availability to the Company of funding required for such development. The calculated net present values 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	506		408		5		4		22,886		21,245		29,238		24,735		1,344		890		10,541		9,966
Developed Non-Producing	13		10		256		204		3,276		2,927		4,000		3,551		242		175		1,723		1,467
Undeveloped	629		540		37		33		4,135		3,763		191,475		167,273		5,987		4,982		39,255		34,062
Total Proved	1,148		958		298		241		30,297		27,935		224,712		195,559		7,572		6,047		51,518		44,495
Probable	1,001		798		100		73		21,044		19,278		263,838		222,255		8,032		5,822		56,613		46,948
Total Proved plus Probable	2,149		1756		398		314		51,340		47,212		488,549		417,815		15,603		11,869		108,132		91,443

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 interest 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	39,165		39,801		38,521		36,661		34,717		0.72
Developed Non-Producing	17,765		14,404		11,803		9,850		8,371		1.34
Undeveloped	218,092		129,002		74,971		41,325		19,727		0.37
Total Proved	275,022		183,207		125,296		87,836		62,815		0.47
Probable	535,761		300,928		183,935		119,851		81,799		0.65
Total Proved plus Probable	810,783		484,135		309,230		207,687		144,614		0.56

Reserves Category	After Future Income Tax Expenses Discounted at (%/year)
	0		5		10		15		20
	(M$)		(M$)		(M$)		(M$)		(M$)
Proved
Developed Producing	39,165		39,801		38,521		36,661		34,717
Developed Non-Producing	17,765		14,404		11,803		9,850		8,371
Undeveloped	218,092		129,002		74,971		41,325		19,727
Total Proved	275,022		183,207		125,296		87,836		62,815
Probable	482,688		280,269		175,199		115,898		79,907
Total Proved plus Probable	757,709		463,476		300,494		203,733		142,721

OUTLOOK

Due to oil price volatility, COVID-19 and concerns of a global economic slowdown, the Company is reviewing its 2020 budget and will not be providing an outlook for 2020 at this time.

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 with respect to: future capital investments the Company’s future cash flows, planned capital expenditures and the source of funding thereof; the Company’s guidance under the heading “Outlook”; projections with respect to the Company’s production, including the effects of well optimization and enhancements on production; future performance expectations of the farm-in to two shut-in Montney oil wells and there impact on funds flow from operations⁽¹⁾ and working capital; the projection of future royalty, operating, transportation and G&A expenses; the projection of the Company’s future taxability; projections relating to the volatility of crude oil and natural gas prices in 2020 and beyond; the effect of the Company’s risk management program, including the impact of derivative financial instruments; and the material weakness that caused the restatement has been remediated. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. 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

⁽¹⁾ Non-IFRS Measures

Throughout this press release, certain terms that are not specifically defined in International Financial Reporting Standards (“IFRS”) are used to analyze Cequence’s operations. In addition to the primary measures of net income (loss) and comprehensive income (loss) and net income (loss) and comprehensive income (loss) per share in accordance with IFRS, Cequence believes that certain measures not recognized under IFRS assist both Cequence and the reader in assessing performance and understanding Cequence’s results. Each of these measures provides the reader with additional insight into the Company’s ability to fund principal debt repayments and capital programs. These terms and financial measures are therefore unlikely to be comparable to similar measures presented by other companies and should not be used to make comparisons between companies. These measures should not be considered alternatives to net income (loss) and comprehensive income (loss) and net income (loss) and comprehensive income (loss) per share as calculated in accordance with IFRS.

Cash netback is a measure used in the oil and gas industry to analyze profitability after general and administrative (“G&A”) and finance expenses.  Cash netback equals operating netback less G&A and finance expenses.  Management utilizes this measure to analyze the Company’s profitability for future capital investment or repayment of debt after considering costs not specifically attributable to its assets or operating areas. The “Operations” table in this press release reconciles cash netback to the IFRS measure net income (loss) and comprehensive income (loss).

Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning costs incurred and net change in non-cash working capital.  The Company uses this measure to analyze operating performance and leverage and considers it 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.  Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of net income (loss) and comprehensive income (loss) per share.

The following table reconciles funds flow from operations, to the IFRS measure, cash flow from operating activities:

	Three months ended December 31,					Twelve months ended December 31,
(thousands of dollars)		2019		2018			2019			2018
Cash flow from operating activities	$	3,226	$	5,201		$	6,561		$	11,758
Decommissioning costs incurred		716		(246	)		4,055			3,756
Net change in non-cash working capital		312		(2,884	)		1,228			(2,427	)
Funds flow from operations	$	4,254	$	2,071		$	11,844		$	13,087

Net debt is a measure that provides Cequence’s total indebtedness. It is calculated as working capital deficiency (excluding commodity contracts and lease liability) plus amounts outstanding in the Company’s Credit Facility plus the principal value of the Company’s subordinated Term Loan. Cequence uses net debt as an estimate of the Company’s assets and obligations expected to be settled in cash. The “Liquidity and Capital Resources” table in the Company’s MD&A reconciles net debt.

Operating netback is a measure used in the oil and gas industry to analyze margin and cash flow. Operating netback equals revenue less royalties, operating and transportation expenses.  Management utilizes this measure to analyze operating performance of its assets and operating areas, compare results to peers and to evaluate drilling prospects. The “Operations” table in this press release reconciles operating netback to the IFRS measure net income (loss) and comprehensive income (loss).

Total revenue equals production revenue gross of royalties and includes realized gains (losses) on commodity contracts. Management utilizes this measure to analyze revenue and commodity pricing and its impact on operating performance. The “Operations” table in this press release reconciles total revenue to the IFRS measure net income (loss) and comprehensive income (loss).

Oil and Gas Metrics

“boe” means barrels of oil equivalent. Boe’s are presented on the basis of one boe for six Mcf of natural gas. Disclosure provided herein in respect of boe 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.

“boe/d” means barrel of oil equivalent per day.

“bbl” means barrels and “bbls” means barrels.

Further definitions and explanations of certain oil and gas metrics can be found in the Company’s Annual Information Form, available under the Company’s issuer profile on SEDAR (www.sedar.com).

OVERVIEW OF CEQUENCE

Cequence is engaged in the exploration for and the development of oil and natural gas reserves.  The Company’s primary focus is the development of its Simonette asset in the Alberta Deep Basin with other non-core assets in Northeast British Columbia and the Peace River Arch of Alberta.  Further information can be found at www.cequence-energy.com.

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

For further information, please contact:

Todd Brown
Chief Executive Officer
Phone: (403) 806-4049
tbrown@cequence-energy.com

Allan Mowbray
Vice President, Finance and Chief Financial Officer
Phone: (403) 806-4041
amowbray@cequence-energy.com

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