Cequence Energy announces first quarter financial results, updated independent reserves evaluation and independent resource evaluation

CALGARY, May 13, 2013 /CNW/ - Cequence Energy Ltd. ("Cequence" or the "Company") (TSX: CQE) is pleased to announce the financial and operating results from the first quarter, an updated independent reserve evaluation with an effective date of April 30, 2013 reflecting increases to the reserves as compared to the reserves evaluation effective January 1, 2013.  In addition, Cequence is pleased to announce an independently prepared resource estimates for its Simonette properties.

Financial and Operating Highlights

The following are financial and operating highlights for the first quarter of 2013:

• Increased funds flow from operations by 58 percent from the prior year to $10.7 million;
• Reduced operating costs by 9 percent from the prior year to $7.24 per boe;
• Reduced total cash costs from prior year by 10 percent to $11.32 per boe;
• Increased the operating netback by 55 percent from prior year to $16.26 per boe;
• Successfully completed 5.0 (4.3 net) wells at Simonette and 1(0.5 net) wells at Ansell and facility expansion at Simonette; and
• Closed the acquisition of an additional 19.2 net sections of Montney rights at Simonette in April.

Reserve and Resource Highlights

The increase to the Company's reserves reflects continued exploration success on its Simonette property in the Deep Basin of Alberta.  In light of the first quarter drilling program at Simonette, the completion of the acquisition of assets from Donnybrook Energy, the divesture of Fir assets and further information from previously drilled wells at Simonette and Ansell, Cequence engaged GLJ Petroleum Consultants Ltd. ("GLJ") to re-evaluate the Company's reserves attributed to Simonette and Ansell and perform a mechanical update on the Company's other properties (the "GLJ Reserves Report").  The Company also engaged GLJ to evaluate the contingent resources attributable to the Montney, Dunvegan and Fahler zones of the Company's Simonette properties (the "GLJ Resource Report") and to calculate the Discovered Petroleum initially in Place ("DPIIP").  The GLJ Reserve Report and GLJ Resources Report are dated May 9, 2013 and effective April 30, 2013 and are collectively referred to herein as the "GLJ Report".  The following are highlights from the GLJ Report:

• Increased proved reserves by 21% from December 31, 2012 to 55.5 MMBOE (previously 46 MMBOE);
• Increased proved plus probable reserves by 24% from December 31, 2012 to 113 MMBOE (previously 91 MMBOE);
• Pre-tax net present value (using a discount rate of 10%) of the Company's total proved reserves as at April 30, 2013 increased 31% to M$549,121 ($2.39 per share) and 12% on a proved plus probable basis to M$1,052,742 ($4.99 per share);
• The GLJ Report estimated contingent resources of 18.5 MMBOE (best estimate) to 82.5 MMBOE (high estimate); and
• The GLJ estimate of DPIIP for the Montney at Simonette is 2.475 trillion cubic feet ("Tcf").

Financial and Operating
					2013	2012	%  Change
Financial ($)
Production revenue ^(1)					22,005	19,864	11
Comprehensive loss					(5,439)	(7,936)	(31)
Per share, basic and diluted					(0.03)	(0.05)	(40)
Funds flow from operations ^(2)					10,652	6,755	58
Per share, basic and diluted					0.05	0.04	25
Production volumes
Natural gas (Mcf/d)					46,306	49,924	(7)
Crude oil (bbls/d)					608	684	(11)
Natural gas liquids (bbls/d)					496	459	8
Total (boe/d)					8,822	9,464	(7)
Sales prices
Natural gas, including realized hedges ($/Mcf)					3.51	2.44	44
Crude oil ($/bbl)					91.90	89.58	3
Natural gas liquids ($/bbl)					52.84	76.63	(31)
Total ($/boe)					27.72	23.07	20
Operating Netback ($/boe)
Price					27.72	23.07	20
Royalties					(2.63)	(2.53)	4
Transportation					(1.59)	(2.08)	(24)
Operating costs					(7.24)	(7.97)	(9)
Operating netback					16.26	10.49	55
Capital Expenditures ($)
Capital expenditures					43,659	40,934	7
Net acquisitions (dispositions) ^(4)					18	(10,942)	(100)
Total capital expenditures					43,677	29,992	46
Net debt and working capital (deficiency) ^(3)					(78,365)	(75,132)	4
Weighted average shares outstanding  (basic and diluted)					200,610	161,856	24
Undeveloped land (net acres)					204,572	238,600	(14)

(1)	Production revenue is presented gross of royalties and realized gains 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 and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities and demand credit facilities and excluding other liabilities.
(4)	Represents the cash proceeds from the sale of assets and cash paid for the acquisition of assets, as applicable.

Funds flow from operations increased to $10.7 million for three months ended March 31, 2013 compared to $6.8 million for the three months ended March 31, 2012.  The increase in funds flow from operations is due largely to a 10 percent increase in revenue resulting from higher natural gas prices and a 16 percent decrease in operating costs.  Funds flow from operations is a non-GAAP measurement as defined below.

Cequence recorded a comprehensive loss of $5.4 million for the first quarter of 2013 compared to a comprehensive loss of $7.9 million in the same period in 2012. The 2013 loss is a result of unrealized hedging losses of $3.3 million and future income tax expense of $2.6 million.

Capital expenditures in the first quarter were $43.7 million compared to $40.9 million in 2012.  Capital expenditures included the drilling of 5 (4.3 net) wells at Simonette and 1 (0.5 net) well at Ansell as well as a facility and pipeline upgrade at Simonette.

Net debt and working capital at March 31, 2013 was $78,365 compared to $75,132 at March 31, 2012.  Cequence has credit facilities totalling $100 million with the next scheduled review of Cequence's credit facility scheduled for May 31, 2013.  Based on the April 30, 2013 reserves Cequence anticipates an increase to the credit facility.

Operations Update

Cequence completed 6.0 gross (4.8 net) horizontal wells in the first quarter including 3.0 gross (3.0 net) Montney wells, 1.0 gross (0.65 net) Falher well, 1.0 gross (0.65 net) Dunvegan well and 1.0 gross (0.49 net) Wilrich well.  Only one well drilled in the first quarter had significant onstream time during the first quarter as production additions at Simonette were restricted by facilities. Production averaged 8,822 boepd (46.3 mmcfd and 1,104 bbls/d of oil and NGL's) in the first quarter compared to 8,951 boepd (47.1 mmcfd and 1,098 bbls/d of oil and NGL's) in the fourth quarter of 2012.

In April, Cequence completed pipeline work and the expansion of the Simonette compression and de-hydration facility at 13-11. Upon completion, total corporate production has averaged approximately 11,000 boepd (57.2 mmcfd and 1,465 bbls/d of oil and NGL's).   The 13-11 facility now has 5,000 horsepower of compression and is currently delivering 52 mmcfd of gross gas sales. Cequence has the ability to expand the capacity of this facility to 120 mmcfd with additional compression.  Cequence is also connected to incremental processing capacity at the Keyera Simonette gas plant and continues to produce gas through that facility.

Three successful Montney wells (3.0 net) were drilled at Simonette in the first quarter. Test rates from the first Montney well of the quarter at 3-18 was previously disclosed and has now been producing for 75 days at an average rate of 5.5 mmcfd and 100 bbls/d of condensate per day.  A second Montney well at 3-21-61-26W5 has been producing for 26 days at an average restricted rate of 4.3 mmcfd and 160 bbls/d of condensate. The current rate is 6.0 mmcfd and 165 bbls/d of condensate.

The final Montney well of the quarter at 9-21-61-26W5 was completed on March 26, 2013.  The well was drilled to a lateral length of 2,399 meters and completed with a 27 stage frac.  Stabilized test rates after 3 days were 8.9 mmcfd and 480 bbls/d of condensate.  On test, the well produced nuisance amounts of sour gas of approximately 800 ppm.  Surface equipment to handle the sour content could not be installed prior to spring break up and will occur as soon as conditions in the field permit access.   If the installation does not occur prior to the end of May, first half production volumes are expected to be approximately 250 boepd below previous guidance of 10,000 boepd.  With the successful startup of new wells at Simonette, older producers were backed out of the system due to high line pressure. Cequence estimates that approximately 2,500 boepd, including initial production from the 9-21 well, is currently tied-in but not producing.

Cequence previously announced test rates from successful Falher and Dunvegan wells at Simonette.  The Falher well at 7-6 has now produced for 35 days at an average rate of 7.5 mmcfd and 202 bbls/d of condensate which is at the Company's model expectation for gas rates, but with a slightly higher condensate ratio. The Dunvegan well has produced for 30 days at an average rate of 12.2 mmcfd and 170 bbls/d of condensate. The current production rate is 16 mmcfd and 170 bbls/d of condensate.  The condensate yield of 14 barrels per mmcf is lower than expected; however, the total condensate production is similar to expected volumes due to the high relative productivity of the well.

Outlook and Recent Developments

Cequence is pleased with the first quarter drilling results and successful expansion of its production facilities at Simonette.  Cequence has achieved record production levels of 11,300 boepd since the commissioning of the facility expansion.

The capital program from the preceding two years has focused on the delineation and de-risking of the Company's asset base.  The emphasis of the Montney play will shift towards development in the second half of 2013 with pad drilling commencing at Simonette in the third quarter.  Cequence expects that pad drilling is the most efficient way to develop the Montney and other zones at Simonette.  To date, Cequence has built twelve pad sites at Simonette serviced with gathering systems and water handling capability through separate flow lines. Cequence expects to drill 2.0 gross (1.0 net) Wilrich wells at Ansell, 1.0 gross (0.65 net) Dunvegan well and 4.0 gross (4.0 net) Montney wells at Simonette before year end.

Cequence forecasts net debt to be approximately $88 million at December 31, 2013 or 1.3 times annualized fourth quarter cash flow.  To reduce the risk of fluctuations in commodity prices, Cequence has hedged approximately 45 percent of its 2013 natural gas production at a price of $3.65 per mcf and 20 percent of 2014 production at an average price of $4.11 per mcf.

Cequence is pleased to provide the following guidance for the year ending December 31, 2013. Cequence provided guidance for the six months ending June 30, 2013 on February 4, 2013 and included the significant assumptions in the annual MD&A dated March 7, 2013.  Other than as disclosed in this press release, Cequence does not currently anticipate material changes to the six month guidance as previously released.

			2013
Average production, BOE/d ^(1)			10,000-10,500
Exit rate production, BOE/d			11,500
Capital expenditures ($)			97 million
Operating costs ($ per boe)			6.75
Royalties (% revenue)			9
Crude - WTI (US$/bbl)			95.00
Natural gas - AECO (Cdn$/GJ)			3.35
Funds flow from operations ($) ^(2)			55 million
December 31, 2013 net debt and working capital ^(3)			88 million
December 31, 2013 net debt to Q4 2013 annualized cash			1.3
Basic shares outstanding ^(4)			210.9 million

(1)	Comprised of 53.1 mmcf/d of natural gas and 1,350 boe/d of oil and natural gas liquids
(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 and working capital deficiency is calculated as cash and net working capital less commodity contract assets and liabilities and demand credit facilities and excluding other liabilities.
(4)	Includes the 10.3 million shares issued April 15, 2013 on the acquisitions of certain Montney assets from Donnybrook Energy

Reserves

GLJ prepared an independent evaluation of the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence.  The GLJ Report was produced using a full evaluation of the Simonette and Ansell properties using first quarter drilling program results.  The reserves attributed to the remaining properties of the Company were mechanically updated from the December 31, 2012 reserve information presented in the Company's Annual Information Form, after giving effect to the acquisition and disposition of certain properties.  Production from the period of January 1 to April 30 totalled 1.2 MMBOE.

The tables below are a summary of the oil, NGL and natural gas reserves attributable to the properties of Cequence as at April 30, 2013, the net present value of future net revenue and the total future net revenue attributable to the Company's reserves, in all cases as based on forecast price and cost assumptions.  In addition, a reconciliation of the proved and proved plus probable reserves of the Company as at April 30, 2013 relative to December 31, 2012 is provided below.  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
Reserves Category			Gross		Net		Gross		Net		Gross		Net		Gross		Net
			(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(MBOE)		(MBOE)
Proved
	Developed Producing		1,018		766		966		784		82,943		73,869		15,808		13,861
	Developed Non-Producing		53		40		125		98		7,226		6,386		1,383		1,203
	Undeveloped		3,654		2,651		2,060		1,902		195,502		170,723		38,298		33,006
Total Proved			4,725		3,457		3,151		2,783		285,671		250,978		55,488		48,070
Probable			5,174		3,486		3,202		2,892		296,874		256,868		57,855		49,190
Total Proved plus Probable			9,899		6,943		6,353		5,676		582,545		507,846		113,444		97,260

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 and Discounted at (%/year)
			0		5		10		15		20
			(M$)		(M$)		(M$)		(M$)		(M$)
Proved
	Developed Producing		318,903		261,515		223,291		196,119		175,820
	Developed Non-Producing		15,795		12,560		10,331		8,704		7,468
	Undeveloped		648,796		441,100		315,498		233,465		176,750
Total Proved			983,494		715,175		549,121		438,288		360,039
Probable			1,228,837		744,147		503,621		364,832		276,129
Total Proved plus Probable			2,212,331		1,459,322		1,052,742		803,120		636,168
Reserves Category			After Future Income Tax Expenses and Discounted at (%/year)
			0		5		10		15		20
			(M$)		(M$)		(M$)		(M$)		(M$)
Proved
	Developed Producing		318,903		261,515		223,291		196,119		175,820
	Developed Non-Producing		15,795		12,560		10,331		8,704		7,468
	Undeveloped		554,703		382,399		276,333		205,984		156,714
Total Proved			889,401		656,474		509,955		410,807		340,003
Probable			922,666		550,943		366,663		260,797		193,613
Total Proved plus Probable			1,812,067		1,207,417		876,619		671,603		533,616

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.

Total Future Net Revenue (Undiscounted)
Reserves Category		Revenue		Royalties		Operating Costs		Capital Development Costs		Abandonment  Costs		Future Net Revenue Before Future Income Tax Expenses		Future Income Tax Expenses		Future Net Revenue After Future Income Tax Expenses
		(M$)		(M$)		(M$)		(M$)		(M$)		(M$)		(M$)		(M$)
Total Proved		2,218,034		305,080		493,869		420,269		15,322		983,494		94,093		889,401
Total Proved plus Probable		4,793,382		718,832		1,028,219		815,313		23,687		2,212,331		400,263		1,812,067

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of April 30, 2013 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
2013		3.92		3.54		94.73		90.05		105.02		2.0		1.00
2014		4.25		3.83		95.00		94.00		103.40		2.0		1.00
2015		4.75		4.28		95.00		94.00		101.52		2.0		1.00
2016		5.25		4.72		97.50		96.50		102.29		2.0		1.00
2017		5.50		4.95		97.50		96.50		100.36		2.0		1.00
2018		5.80		5.22		97.50		96.50		100.36		2.0		1.00
2019		5.91		5.32		98.54		97.54		101.44		2.0		1.00
2020		6.03		5.43		100.51		99.51		103.49		2.0		1.00
2021		6.15		5.54		102.52		101.52		105.58		2.0		1.00
2022		6.27		5.64		104.57		103.57		107.71		2.0		1.00
Thereafter escalation rate of 2%

Reconciliation of Company Gross Reserves by Product Type

The following table sets forth the changes between the Company's reserve volume estimates made as at April 30, 2013 and the corresponding estimates as at December 31, 2012, using forecast prices and costs:

			Light and Medium Crude Oil		Natural Gas (associated & non- associated)		NGL		Total Oil Equivalent
Factors			(Mbbl)		(MMcf)		(Mbbl)		(MBOE)
TOTAL PROVED
December 31, 2012			3,765		240,205		2,657		46,459
	Extensions & Improved Recovery		824		46,438		553		9,117
	Technical Revisions		10		1,256		14		233
	Discoveries		-		-		-		-
	Acquisitions		201		9,097		86		1,803
	Dispositions		-		(4,575)		(92)		(854)
	Economic Factors		-		-		-		-
	Production		(73)		(6,378)		(68)		(1,204)
April 30, 2013^(1)			4,726		286,044		3,154		55,554
TOTAL PROVED PLUS PROBABLE
December 31, 2012			7,615		470,386		5,178		91,193
	Extensions & Improved Recovery		1,635		89,718		1,009		17,597
	Technical Revisions		187		12,001		146		2,333
	Discoveries		-		-		-		-
	Acquisitions		536		24,256		230		4,808
	Dispositions		-		(6,853)		(137)		(1,279)
	Economic Factors		-		-		-		-
	Production		(73.3)		(6,378)		(68)		(1,204)
April 30, 2013^(1)			9,902		583,130		6,358		113,448

Note:
(1)	Totals may not add due to rounding.

Contingent Resources - Simonette

Cequence retained GLJ to conduct an independent resource evaluation to assess contingent resources at Simonette with an effective date of April 30, 2013.  Contingent resources were evaluated for the Upper Montney Play, Fahler F Channel and Dunvegan Channel and are presented herein in aggregate.

All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of April 30, 2013.

The estimates of volumes of, and the net present value of the future net revenue attributable to contingent resources in this news release are derived from the GLJ Resources Assessment.  The GLJ Resources Assessment was prepared in accordance with NI 51-101 by GLJ, an independent qualified reserve evaluator.

Summary information regarding contingent resources and net present values of future net revenues from contingent resources at Simonette are set forth below:

Gross and Net Contingent Resources at Simonette as at April 30, 2013 ^(1) - Forecast Prices and Costs ^(2)
		Gross			Net
		Contingent Resources^(3)
		Best (Mbbl)		High (Mbbl)		Best (Mbbl)		High (Mbbl)
Light and Medium Oil (MBOE)		2,060		9,145		1,531		6,425
Natural Gas (MMcf)		93,208		416,150		83,144		368,628
NGL (MBOE)		883		3,997		847		3,904
Total Oil Equivalent (MBOE)		18,478		82,500		16,235		71,767

Summary of Net Present Value of Future Net Revenues of Contingent Resources at Simonette as at April 30, 2013 - Forecast Prices and Costs ^(2)
	Before Income Taxes, Discounted at (% per year) ^(7)
(M$)	0%	5%	8%	10%	12%	15%	20%
Best Estimate (C2) ^(4)	395,704	236,930	179,981	151,441	128,345	101,293	69,990
High Estimate (C3) ^(5)	2,183,165	1,106,878	788,246	641,212	528,245	402,684	266,529

Notes:
(1)		The contingent resource assessments were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101. Contingent resource is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets.
(2)		The forecast price and cost assumptions utilized in the GLJ Report were also utilized by GLJ in preparing the contingent resource assessments.
(3)		GLJ prepared the estimates of contingent resource shown for Simonette using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table.  Gross means the Company's working interest share in the contingent resource before deducting royalties.
(4)		Best estimate is considered to be the best estimate of the quantity of contingent (C2) resources that will actually be recovered.  It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate.  Those contingent resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will be equal or exceed the estimate.
(5)		High estimate is considered to be an optimistic estimate of the quantity of contingent (C3) resources that will actually be recovered. It is unlikely that the actual remaining quantities of contingent resources recovered will meet or exceed the high estimate. Those contingent resources at the high end of the estimate range have a lower degree of certainty - a 10% confidence level - that the actual quantities recovered will equal or exceed the estimate.
(6)		Low estimate is considered to be a conservative estimate of the quantity of contingent resources (C1) that will actually be recovered. It is likely that actual remaining quantities recovered will exceed the low estimate. Those resources included in the low estimate range have the highest degree of certainty - a 90 percent probability - that the actual quantities recovered will equal or exceed the estimate. There were no low estimate resources assigned in the GLJ evaluation.
(7)		The net present value of future net revenue attributable to the contingent resources does not necessarily represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation.

The primary contingencies which currently prevent the classification of Cequence's contingent resource as reserves include but are not limited to:

• preparation of firm development plans, including determination of the specific scope and timing of projects;
• project sanction;
• access to capital markets;
• regulatory approvals;
• access to required services and field development infrastructure;
• oil and natural gas prices in Canada;
• demonstration of economic viability;
• future drilling program and testing results;
• further reservoir delineation and studies;
• facility design work;
• limitations to development based on adverse topography or other surface restrictions; and
• the uncertainty regarding marketing and transportation of petroleum from development areas.

Resignation of Director

As a result of increased commitments, Mr. Paul Colborne has elected to resign as a director of the Company effective immediately.  The board and management of the Company would like to thank Mr. Colborne for his contribution over the years, and wish him well in his future endeavours.

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: an expected increase to its credit facility; business strategy and objectives; development, exploration, acquisition and disposition plans, including the anticipated benefits resulting therefrom and the timing thereof; reserve and resource quantities and the discounted present value of future net cash flows from such reserves or resources; and future production levels and facility capabilities. 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. 

"Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. It is also appropriate to classify as contingent resource the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Cequence will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future.  The net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources.  Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.

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 the first quarter of 2013, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 26:1 ("Value Ratio"). The Value Ratio is obtained using the first quarter 2013 WTI average price of $94.30 (US$/Bbl) for crude oil and the first quarter 2013 NYMEX average price of $3.48 (US$/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.

DISCOVERED PETROLEUM INITIALLY IN PLACE (DPIIP): DPIIP is equivalent to discovered resources and is defined in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves and contingent resources; the remainder is unrecoverable. "Contingent Resources" are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be economically recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. The Contingent Resources estimates and the DPIIP estimates are estimates only and the actual results may be greater or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources except to the extent identified as proved or probable reserves. "Best estimate" is defined in COGEH with respect to entity-level estimates, as the value derived by an evaluator using deterministic methods that best represent the expected outcome with no optimism or conservatism. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

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

 

 

 

SOURCE: Cequence Energy Ltd.

Paul Wanklyn, President and Chief Executive Officer, [phone], [email protected]

David Gillis, Vice President, Finance and Chief Financial Officer, [phone], [email protected]