Cequence Energy Ltd. Announces Over 36 % Growth in Reserves and Reserve Value and Fourth Quarter and Year End 2011 Results

CALGARY, March 8, 2012 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: "CQE") is pleased to announce its 2011 year end reserves and its operating and financial results for the three months and the year ended December 31, 2011.

Reserves Highlights

• Increased proved plus probable reserves by 38 percent from the prior year to 67.4 MMBOE, comprised of 350.7 MMcf of natural gas and 9.0 MMBOE of oil and NGLs;
• Increased the net present value of the future net revenue from the Company's proved plus probable reserves by 36 percent from the prior year to $715.8 million (using a discount rate of 10%);
• Increased proved reserves by 28 percent from the prior year to 35.1 MMBOE, comprised of 182.6 MMcf of natural gas and 4.7 MMBOE of oil and NGLs ;
• Increased proved developed producing reserves by 13 percent from the prior year to 14.7 MMBOE and increased the net present value of the future net revenue from proved developed producing reserves by 12 percent from the prior year to $202.9 million (using a discount rate of 10%);
• Achieved a net asset value at December 31, 2011 of $715.2 million or $4.42 per share, based on the net present value of the future net revenue from the Company's proved plus probable reserves;
• Realized a net asset value of $450.3 million or $2.78 per share, based on the net present value of the future net revenue from the Company's proved plus probable reserves with benchmark future pricing used in the Company's reserve report at December 31, 2011 adjusted to March 5, 2012 escalated strip prices;
• Achieved finding, development and acquisition costs including changes to future development capital of $13.42 per boe on a proved plus probable basis and $19.26 per boe on a proved basis;
• Total proved plus probable reserves at Simonette increased by 99 percent to 252.6 MMcf of natural gas and 7.1 MMBOE of oil and NGLs from 132.1 MMcf of natural gas and 2.7 MMBOE of oil and NGLs in 2010, representing 73 percent of the Company's total proved plus probable reserves at December 31, 2011;
• The 2011 independent reserves evaluation includes 38 net future horizontal drilling locations in the Montney at Simonette;
• Replaced 665 percent of 2011 annual production on a proved plus probable basis and 336 percent on a proved basis, including revisions; and
• Based on 2011 annual production of 9,010 boepd, Cequence has a reserve life index of 10.7 years on a proved basis and 20.5 years on a proved plus probable basis.

Fourth Quarter Financial Highlights

• Increased average production to 8,879 boepd for the quarter (47.2 MMcf/d of natural gas plus 1,012 bbls/d of oil and NGL's), a 19 percent increase over the fourth quarter of 2010;
• Increased funds flow from operations by 31 percent to $10.0 million or $0.06 per share from $7.6 million or $0.06 per share in the fourth quarter of 2010;
• Reduced operating costs per boe to $8.60, an improvement of 16 percent from the fourth quarter of 2010;
• Reduced general and administrative expenses by 37 percent to $2.04 per boe from $3.23 per boe in the fourth quarter of 2010; and
• Increased netbacks before hedging by 1 percent to $13.98 per boe from $13.86 per boe in the fourth quarter of 2010, as the 6 percent decline in realized sales price before hedging was more than offset by the cost reductions discussed above.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

Financial Highlights

(000's except per share amounts)	Three months ended December 31							Year Ended December 31
		2011		2010			% Change		2011		2010		% Change
Financial ($)
Production revenue ^(1)	$	23,527	$	22,352			5	$	101,996	$	54,570		87
Comprehensive loss ^(2)		(15,598)		(23,206)			(33)		(20,158)		(52,349)		(61)
Per share, basic and diluted		(0.10)		(0.18)			(44)		(0.14)		(0.75)		(81)
Funds flow from operations ^(2) (3)		10,002		7,629			31		42,262		15,997		164
Per share, basic and diluted		0.06		0.06			-		0.29		0.23		26
Production volumes
Natural gas (Mcf/d)		47,203		8,702			22		47,825		22,956		108
Crude oil (bbls/d)		503		478			5		575		333		73
Natural gas liquids (bbls/d)		509		557			(9)		464		292		59
Total (boe/d)		8,879		7,485			19		9,010		4,451		102
Sales prices
Natural gas, including realized hedges ($/Mcf)	$	3.59	$	4.40			(18)	$	4.03	$	4.63		(13)
Crude oil ($/bbl)		97.15		77.24			26		92.60		74.12		25
Natural gas liquids ($/bbl)		73.19		64.13			14		71.99		63.88		13
Total ($/boe)	$	28.80	$	32.46			(11)	$	31.02	$	33.59		(8)
Operating Netbacks ($/boe)
Price	$	28.80	$	32.46			(11)	$	31.02	$	33.59		(8)
Royalties		(3.75)		(3.80)			(1)		(4.18)		(3.55)		18
Transportation		(1.93)		(2.25)			(14)		(2.18)		(2.68)		(19)
Operating costs		(8.60)		(10.20)			(16)		(9.02)		(10.90)		(17)
Operating netback	$	14.52	$	16.21			(10)	$	15.64	$	16.46		(5)
Capital expenditures	$	56,335	$	24,392			131	$	149,601		64,120		133
Corporate acquisitions ^(2)		-		-			-		-		155,602		(100)
Property acquisitions (net) ^(2)		-		(4,707)			(100)		(23,023)		43,157		N/A
Total capital expenditures	$	56,335	$	19,685			186	$	126,578	$	262,879		(52)
Net debt and working capital (deficiency) ^(4)		(51,442)		(72,739)			(29)		(51,442)		(72,739)		(29)
Weighted average shares outstanding     (basic and diluted)		161,818		127,258			27		147,558		69,713		112
Undeveloped land (net acres)		254,400		293,800			(13)		254,400		293,800		(13)

(1)	Production revenue is presented gross of royalties and includes realized gain on commodity contracts.
(2)	2010 figures have been restated from previously reported amounts resulting from the application of IFRS. See 'Adoption of International Financial Reporting Standards' in the MD&A for the year ended December 31, 2011.
(3)	Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liability expenditures, proceeds from the sale of commodity contracts and net changes in non-cash working capital.
(4)	Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract asset and demand credit facilities and excluding other liabilities.

Fourth Quarter Financial Highlights

For the quarter ended December 31, 2011, Cequence reported funds flow from operations of $10.0 million compared to $7.6 million in the fourth quarter of 2010. The increase in funds flow from operations is a result of increased production volumes and lower operating, transportation and general and administrative costs from the corresponding period in 2010. Sales prices including hedging decreased 11 percent from the fourth quarter of 2010 due to lower natural gas prices and lower hedging revenues. Cequence recorded a comprehensive loss of $15.6 million for the fourth quarter of 2011 compared to a comprehensive loss of $23.2 million in the same period in 2010 primarily due to lower depletion and impairment charges in the fourth quarter of 2011, as compared to 2010. Capital expenditures in the fourth quarter of 2011 totalled $56.3 million and were focused on drilling, completion and facilities expenditures at Simonette.

Year End Financial Highlights

For the year ended December 31, 2011, Cequence recorded significant increases in revenue, funds flow from operations and capital expenditures from the prior year. During 2010, Cequence completed a series of acquisitions and dispositions for total deemed consideration of $198.8 million that significantly increased the size of the Company. The majority of these acquisitions occurred late in 2010, and thus resulted in the increases described above in 2011 as compared to 2010.

For the year ended December 31, 2011 Cequence reported a comprehensive loss of $20.2 million compared to a comprehensive loss of $52.3 million in 2010 primarily due to lower depletion and impairment charges in 2011 as compared to 2010. Funds flow from operations for the year ended December 31, 2011 increased to $42.3 million from $16.0 million in the prior year due to higher production volumes and lower operating, general and administrative and transportation costs, on a per boe basis.

The Company exited 2011 with net debt of $51.4 million on bank lines totalling $110 million.

Cequence provided 2012 capital budget guidance on February 14, 2012.

The Company's financial statements and management's discussion and analysis for the periods ended December 31, 2011 and the annual information form for the year ended December 31, 2011, which includes information concerning the reserves and other oil and gas information in the form required by National Instrument 51-101 ("NI 51-101"), are available on SEDAR at www.sedar.com.

Operating Highlights and Recent Developments

• Further rationalized the Company's asset base with the disposition of non-core assets for proceeds of $45.2 million in 2011, allowing Cequence to focus on its core asset base at Simonette;
• Drilled and completed a total of 6 gross (4.5 net) horizontal wells in the Montney gas/condensate fairway at Simonette in 2011 and during the first quarter of 2012. 3 wells are currently on production at an average 30-day IP rate of 4.6 MMcf/d and 3 wells have tested, based on a minimum 4 day test period, at an average rate of 7.7 MMcf/d (as compared to the Company's model IP rate of 4.5 MMcf/d). An additional 2 gross (1.5 net) Montney horizontal wells are scheduled for completion prior to spring break-up;
• De-risked approximately 36 net sections of land at Simonette for Montney liquids-rich gas development, with an additional 34 net sections at Simonette considered highly prospective for the Montney;
• Completed and expanded a gas compression and dehydration facility and gathering system at Simonette in 2011, allowing for an additional 35 MMcf/d of processing capacity and resulting in total capacity of 57 MMcf/d of raw gas at Simonette; and
• Scheduled to complete infrastructure spending related to the previously announced Aux Sable project in the first quarter of 2012, which will expand the Company's gathering system at Simonette and is expected to reduce operating costs at Simonette to approximately $4 per boe or $0.67 per mcfe. This system will provide Cequence with access to up to 120 MMcf/d of capacity through the Alliance pipeline.

Recent Transactions

On March 1, 2012, the Company closed the previously announced sale of non-producing properties in Northwest Alberta for proceeds of $13.2 million, subject to adjustments.

On March 2, 2012, the Company announced that it had amended the terms of the 2012 Warrants (see the 2011 Annual Financial Statements). Following the amendment, the 2012 Warrants were issuable at $1.80 per share, based on the 10 day volume weighted average trading price of the Company's shares on the TSX for the period February 6, 2012 to February 17, 2012 and were to expire March 21, 2012. On March 8, 2012, the Company and the holder of the 2012 Warrants irrevocably agreed to cancel the 2012 Warrants at no cost to the Company and no redress to the holder of the 2012 Warrants.

Outlook

The balance of Cequence's 2012 budgeted capital spending will target the Company's highest liquids-weighted prospects. The Company considers approximately 65 percent of its remaining 2012 budget to be discretionary. The majority of the 2012 budget is directed towards drilling in the Montney at Simonette, which has anticipated liquids yields ranging from 25 to 60 bbls/MMcf. The Company also plans to target the Dunvegan at Simonette, which has anticipated liquids yields of up to 75 bbls/MMcf and to test a new zone in the Falher at Simonette. The Company closely monitors fluctuations in natural gas prices and will adjust the 2012 budget if facts and circumstances require, in order to maintain the strength of the Company's balance sheet.

Reserves

In accordance with NI 51‐101, GLJ Petroleum Consultants Ltd. ("GLJ") prepared a reserve report, effective as at December 31, 2011 for the oil, natural gas liquids ("NGL") and natural gas reserves attributable to the properties of Cequence (the "GLJ Report").

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. 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 and Gas Reserves

			Light and Medium Crude Oil				NGL				Natural Gas				Total Oil Equivalent
			Gross		Net		Gross		Net		Gross		Net		Gross		Net
Reserves Category			(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(MBOE)		(MBOE)
Proved
	Developed Producing		791		623		923		727		77,765		69,021		14,675		12,854
	Developed Non-Producing		152		121		121		102		8,617		7,946		1,709		1,548
	Undeveloped		1,567		1,159		1,096		1,008		96,185		85,767		18,694		16,461
Total Proved			2,510		1,903		2,140		1,837		182,568		162,734		35,077		30,862
Probable			2,302		1,606		2,034		1,760		168,178		148,137		32,366		28,056
Total Proved plus Probable			4,811		3,509		4,174		3,597		350,745		310,872		67,443		58,918

Notes:
	(1)	Columns may not add during 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
			(M$)		(M$)		(M$)		(M$)		(M$)
Proved
	Developed Producing		304,347		243,162		202,850		174,549		153,683
	Developed Non-Producing		34,342		26,367		21,513		18,175		15,710
	Undeveloped		381,239		244,937		165,083		114,349		80,103
Total Proved			719,928		514,466		389,446		307,074		249,495
Probable			866,274		499,645		326,304		230,130		170,500
Total Proved plus Probable			1,586,203		1,014,111		715,750		537,204		419,995

Reserves Category			After Future Income Tax Expenses Discounted at (%/year)
			0		5		10		15		20
			(M$)		(M$)		(M$)		(M$)		(M$)
Proved
	Developed Producing		304,347		243,162		202,850		174,549		153,683
	Developed Non-Producing		34,342		26,367		21,513		18,175		15,710
	Undeveloped		346,603		227,583		155,851		109,186		77,091
Total Proved			685,293		497,112		380,214		301,911		246,483
Probable			650,902		375,922		246,381		174,563		129,959
Total Proved plus Probable			1,336,194		873,034		626,595		476,474		376,443

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, 2012 in the GLJ Report in estimating Cequence's reserves data using forecast prices and costs:

Year		Natural Gas				Light Crude Oil				Pentanes Plus		Inflation Rates		Exchange Rate
		Henry Hub		AECO Gas Price		WTI		Edmonton		Edmonton
		($US/MMBtu)		($Cdn/MMBtu)		($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		%/year		($US/$Cdn)
Forecast
2012		3.80		3.49		97.00		97.96		107.76		2.0		0.980
2013		4.50		4.13		100.00		101.02		108.09		2.0		0.980
2014		5.00		4.59		100.00		101.02		105.06		2.0		0.980
2015		5.50		5.05		100.00		101.02		105.06		2.0		0.980
2016		6.00		5.51		100.00		101.02		105.06		2.0		0.980
2017		6.50		5.97		100.00		101.02		105.06		2.0		0.980
2018		6.76		6.21		101.35		102.40		106.49		2.0		0.980
2019		6.89		6.33		103.38		104.47		108.65		2.0		0.980
2020		7.03		6.46		105.45		106.58		110.84		2.0		0.980
2021		7.17		6.58		107.56		108.73		113.08		2.0		0.980
Thereafter escalation rate of 2%

Finding, development and acquisition costs ("FD&A") and finding and development costs ("F&D") both including and excluding future development capital ("FDC") have been calculated in accordance with NI 51-101. Cequence's finding, development and acquisition costs are as follows:

			Proved		Proved Plus Probable
FD&A Including Change in FDC
	2011 FD&A Costs ($000s)		117,868		117,868
	2011 Change in FDC ($000s)		94,689		175,653
	2011 Capital Expenditures including change in FDC ($000s)		212,557		293,521
	2011 Reserve Additions (MBOE)		11,035		21,870
	2011 FD&A Including Change in FDC ($/BOE)		19.26		13.42
	3 year average FD&A Including Change in FDC ($/BOE)		18.67		13.01
F&D Including Change in FDC
	2011 F&D Costs ($000s)		149,601		149,601
	2011 Change in FDC ($000s)		105,810		200,032
	2011 Capital Expenditures including change in FDC ($000s)		255,411		349,633
	2011 Reserve Additions (MBOE)		12,091		25,106
	2011 F&D Including Change in FDC ($/BOE)		21.12		13.93
	3 year average F&D Including Change in FDC ($/BOE)		26.98		17.40
FDC - December 31, 2011 ($000s)			236,399		426,484
FDC - December 31, 2010 ($000s)			141,710		250,831
2011 Change in FDC ($000s)			94,689		175,653
FDC Related to 2011 Net Acquisitions (Dispositions) ($000s)			(11,121)		(24,379)
2011 Change in FDC Excluding FDC on Net Acquisitions (Dispositions) ($000s)			105,810		200,032

Notes:
	(1)	FD&A including change in FDC in respect of 2010 proved, 2010 proved plus probable, 2009 proved and 2009 proved plus probable reserves is included in the Company's annual information form for the year ended December 31, 2010 dated March 10, 2011 (the "2010 AIF") which is available at www.sedar.com.
	(2)	F&D including change in FDC in respect of 2010 proved, 2010 proved plus probable, 2009 proved and 2009 proved plus probable reserves is included in the 2010 AIF.
	(3)	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 reserve additions for that year.
	(4)	In addition to F&D costs, Cequence also calculates FD&A costs which incorporate both the costs and associated reserve additions related to acquisitions net of any dispositions during the year. Since acquisitions can have a significant impact on Cequence's annual reserve replacement costs, the Company believes that FD&A costs provide a more meaningful portrayal of Cequence's cost structure.

Substantially all of the Company's drilling expenditures during the year were on assets located in the Simonette area. The GLJ Report classifies all reserve changes due to discoveries, extensions, improved recoveries, technical revisions, acquisitions and economic factors on properties acquired or disposed of during the 2010 year as "Acquisitions" or "Dispositions". This definition includes the results of drilling operations before or after an acquisition or disposition is closed. The result is the F&D calculation for the 2010 fiscal year included in the 3 year average figure in the table above is based on the information contained in the GLJ reserve reconciliation.

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.

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 "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "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 its guidance and forecasts: business strategy and objectives; development, exploration, acquisition and disposition plans and the timing thereof; reserve quantities and the discounted present value of future net cash flows from such reserves; future production levels. 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, however, 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

The press release contains references to terms commonly used in the oil and gas industry.  Netback is not defined by IFRS in Canada and is referred to as a non-GAAP measure.  Netbacks equal total revenue less royalties, operating costs and transportation costs.  Management utilizes this measure to analyze operating performance. 

Funds flow from operations is a non-GAAP term 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.

Non-GAAP measures do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers.

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 2011, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 24:1 ("Value Ratio").  The Value Ratio is obtained using the 2011 WTI average price of $95.11 (US$/Bbl) for crude oil and the 2011 NYMEX average price of $4.03 (US$/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 TSX has neither approved nor disapproved the contents of this news release.

 

 

Paul Wanklyn, Chief Executive Officer, [phone], [email protected]
David Gillis, Chief Financial Officer, [phone], [email protected]