Cequence Energy Announces Operational Update, 2017 Financial and Operating Results and Reserves

CALGARY, March 13, 2018 /CNW/ – Cequence Energy Ltd. (“Cequence” or the “Company”) (TSX: CQE) is pleased to announce its year-end reserve evaluation as prepared by its qualified independent reserve evaluator as well as its operating and financial results for the fourth quarter and year ended December 31, 2017. 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.

2017 Highlights

Achieved full year 2017 production of 8,139 boe/d and increased liquids weighting to 17 percent;
Increased funds flow from operations from 2016 by 72% to $19.3 million or $0.08/share;
Improved egress with firm service contracted for all of the Company’s Simonette natural gas production;
Added market diversity away from AECO with 10,850 GJ/d of production to be sold at Dawn beginning April 1, 2018; and
Drilled, completed, and tied in 3 gross (2 net) Dunvegan oil wells this winter with production to commence the middle of March, 2018.

Comparative financial and operating information for 2017 and 2016 are as follows:

	Three months ended December 31,			Twelve months ended December 31,
(000’s except per share and per unit amounts)
	2017	2016	% Change	2017	2016	% Change
FINANCIAL
Total revenue⁽¹⁾	13,585	17,253	(21)	65,836	59,074	11
Comprehensive loss	(6,638)	(9,077)	(27)	(99,362)	(28,057)	(254)
Per share – basic and diluted	(0.03)	(0.04)	(25)	(0.40)	(0.13)	(208)
Funds flow from operations ⁽²⁾⁽⁵⁾	1,583	6,625	(76)	19,329	11,250	72
Per share, basic and diluted	0.01	0.03	(67)	0.08	0.05	60
Capital expenditures, before acquisitions (dispositions)	5,593	11,460	(51)	25,857	22,590	14
Capital expenditures, including acquisitions (dispositions)	1,316	11,406	(88)	21,580	17,296	25
Net debt ⁽³⁾	(68,501)	(64,031)	7	(68,501)	(64,031)	7
Weighted average shares outstanding – basic & diluted	245,528	235,028	4	245,528	217,061	13
OPERATING
Production volumes
Natural gas (Mcf/d)	33,331	45,005	(26)	40,466	45,442	(11)
Crude oil (bbls/d)	283	140	102	344	177	94
Natural gas liquids (bbls/d)	257	209	23	254	237	7
Condensate (bbls/d)	617	760	(19)	797	841	(5)
Total (boe/d)	6,713	8,609	(22)	8,139	8,826	(8)
Sales prices
Natural gas, including realized hedges ($/Mcf)	2.33	2.92	(20)	2.53	2.27	11
Crude oil and condensate, including realized hedges ($/bbl)	66.73	56.27	19	61.44	52.17	18
Natural gas liquids ($/bbl)	38.55	25.61	51	30.72	21.94	40
Total ($/boe)	22.00	21.78	1	22.16	18.29	21
Netback ($/boe)
Price, including realized hedges	22.00	21.78	1	22.16	18.29	21
Royalties	(0.63)	(0.59)	7	(1.06)	(0.48)	121
Transportation	(1.66)	(1.45)	14	(1.88)	(1.24)	52
Operating costs	(12.91)	(7.81)	65	(9.29)	(8.49)	9
Operating netback	6.80	11.93	(43)	9.93	8.08	23
General and administrative⁽⁵⁾	(1.88)	(1.81)	4	(1.48)	(2.77)	(47)
Interest⁽⁴⁾	(2.46)	(1.92)	28	(2.07)	(1.93)	7
Cash netback	2.46	8.20	(70)	6.38	3.38	89

Notes:
(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) less the principal value of senior notes.
(4)	Represents finance costs less amortization on transaction costs and accretion expense on senior notes and provisions.
(5)	For the three and twelve months ended December 31, 2016, general and administrative expenses and funds flow from operations includes $nil and $2,341 in restructuring charges (2017 – $nil).

Financial

Natural gas prices remained low in both 2016 and 2017 with AECO prices averaging $2.18/mcf and $2.23/mcf, respectively. Conversely, crude oil and NGL prices increased year over year contributing to an increase in annual funds flow from operations of 72 percent to $19.3 million. Fourth quarter funds flow of $1.6 million was negatively impacted by low AECO natural gas prices in October and higher operating costs related to a field water management project which was completed in the fourth quarter. For the twelve months ended December 31, 2017, the Company recorded a comprehensive loss of $99.4 million as the Company recorded 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 $25.9 million ($21.6 net of dispositions) and focused on wells with higher oil and liquids content. Total capital was allocated as follows: $14.2 million (55%) weighted toward Q1 2017 completion and equipping of Montney wells, $7.2 million (28%) toward Dunvegan oil drilling, completion, equipping, and oil facility tie-in, and $2.4 million (9%) for operating initiatives including water disposal well completion, equipment, and related disposal facility spending. With the outlook for natural gas prices remaining weak in 2018, the Company does not expect to drill any additional wells in the first half of 2018.

Financial leverage has improved over the past year as the Company managed total debt levels by reducing capital expenditures. December 31, 2017 net debt is $68.5 million (December 31, 2016 – $64.0 million) or 3.5 times trailing annual funds flow (December 31, 2016 – 5.7 times). The senior credit facility of $12 million remain undrawn other than letters of credit of $1.5 million. Reflecting the challenging commodity pricing environment and its effects on the Company’s cash flows and liquidity and the Company’s current debt, among other factors, the Company’s financial statements continue to disclose there is significant doubt in the Company’s ability to continue as a going concern. Further details are set forth in the annual financial statements available on Sedar.

The Company has hedged approximately 13% of its 2018 estimated production and has diversified its natural gas sales with a contract to sell 10,850 GJ/d in the Dawn, Ontario market. In the fourth quarter the Company’s NGTL firm service was increased to 35,000 mmcf/d at Simonette which is expected to improve netbacks by reducing the Company’s reliance on more expensive short-term transportation.

2017 Operational and Production

During the winter season of 2017/2018, Cequence has drilled and completed 3 gross (2 net) Dunvegan oil wells as follow up to the successful 2 gross (1 net) in 2016/2017. The new wells are scheduled to be producing in mid-March, 2018.

For the year ended December 31, 2017, operating costs averaged $9.29 per boe in 2017, up 9% from 2016, with operating costs up 65% in the fourth quarter to $12.91/boe. In the second half of 2017 the Company had one time expenses associated with accelerating a water handling and disposal project to reduce its surface water at the Simonette field. Total costs of the project were $1.3 million ($2.15/boe) for the fourth quarter and $3.3 million year to date ($1.36/boe). The onetime costs were associated with storing water at surface, transferring water to a water disposal well and dismantling surface tanks. During the water disposal project, 2/3rds of the Simonette field was shut-in for a week to utilize the pipeline system for water transfer. This pipeline use was conducted during a period of low gas prices. The water project was completed in December and is expected to significantly reduce ongoing water handling costs beginning in January 2018. Total operating costs for 2018 are expected to be approximately $9.50 – $10.50 per boe.

Corporate production for the three and twelve months ended December 31, 2017 averaged 6,713 boe/d and 8,139 boe/d, respectively, compared to production of 8,609 boe/d and 8,826 boe/d in 2016. Oil and liquids production for the same periods increased to 1,157 bbl/d and 1,359 bbl/d up 4% and 8% respectively.

2017 Independent Reserve Evaluation Matters

GLJ Petroleum Consultants (“GLJ”) prepared the reserves report effective December 31, 2017 (collectively referred to herein as 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 (“NI 51-101”). Reserves highlights of the Company include:

Corporate reserves were 14.1 MMboe proved developed producing, 61.9 MMboe proven, and 124.2 MMboe on a proved plus probable basis.
Before production, Dunvegan oil total proved and proved plus probable reserves increased by 129% and 43% respectively to 1.9 MMboe and 3.0 MMboe.
Dunvegan oil total proven and proven plus probable net present values at 10% discount rate are $23.8 million and $34.0 million respectively using GLJ January 1, 2018 prices
Booked Dunvegan oil inventory is 3.5 net proven and 5.5 net proved plus probable locations.
Decreased Montney proved reserves by 12% to 49.6 MMboe and proved plus probable reserves by 11% to 100.6 MMboe. 15 net proven Montney locations representing 8.5 MMboe were adjusted to a later drilling date moving them into a probable category. A separate 14 net proved plus probable Montney locations representing 10.3 MMboe were removed for current economic factors.
Recognized 4 additional proved plus probable locations offsetting the Q1 2017 Montney development program.

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⁾
Reserves Category		(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	MMcf	MMcf	(Mbbl)	(Mbbl)	(MBOE)	(MBOE)
Proved
	Developed Producing	255	211	0	0	31,416	28,818	41,358	35,574	1,734	1,190	14,118	12,133
	Developed Non- Producing	19	16	0	0	4,017	3,563	4,149	3,444	160	100	1,540	1,285
	Undeveloped	645	544	0	0	27,587	25,852	206,937	178,806	6,513	5,430	46,245	40,083
Total Proved		919	771	0	0	63,021	58,233	252,444	217,824	8,407	6,720	61,903	53,501
Probable		567	467	0	0	58,670	53,559	261,162	216,680	8,425	6,392	62,297	51,899
Total Proved plus Probable		1,486	1,238	0	0	121,690	111,793	513,605	434,504	16,832	13,112	124,200	105,400


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

		Before Future Income Tax Expenses Discounted at (%/year)
			0	5	10	15	20	10
Reserves Category			(M$)	(M$)	(M$)	(M$)	(M$)	($/mcfe)
Proved
	Developed Producing		121,056	101,934	87,683	77,010	68,832	1.20
	Developed Non-Producing		18,534	13,814	10,712	8,577	7,043	1.39
	Undeveloped		447,989	240,361	133,412	74,259	39,592	0.55
Total Proved			587,580	356,108	231,807	159,846	115,467	0.72
Probable			943,817	421,811	219,784	126,233	77,182	0.71
Total Proved plus Probable			1,531,396	777,919	451,591	286,080	192,649	0.71

		After Future Income Tax Expenses Discounted at (%/year)
			0	5	10	15	20
Reserves Category			(M$)	(M$)	(M$)	(M$)	(M$)
Proved
	Developed Producing		121,056	101,934	87,683	77,010	68,832
	Developed Non-Producing		18,534	13,814	10,712	8,577	7,043
	Undeveloped		447,989	240,361	133,412	74,259	39,592
Total Proved			587,580	356,108	231,807	159,846	115,467
Probable			690,954	321,385	173,324	102,421	64,067
Total Proved plus Probable			1,278,533	677,493	405,131	262,267	179,534

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, 2018 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
2018	2.85	2.20	59.00	70.25	76.42	2.0	0.790
2019	3.00	2.54	59.00	70.25	74.68	2.0	0.790
2020	3.25	2.88	60.00	70.31	74.38	2.0	0.800
2021	3.50	3.24	63.00	72.84	77.16	2.0	0.810
2022	3.70	3.47	66.00	75.61	79.88	2.0	0.820
2023	3.86	3.58	69.00	78.31	82.53	2.0	0.830
2024	3.94	3.66	72.00	81.93	86.14	2.0	0.830
2025	4.02	3.73	75.00	85.54	89.76	2.0	0.830
2026	4.10	3.80	77.33	88.35	92.57	2.0	0.830
2027	4.18	3.88	78.88	90.22	94.43	2.0	0.830
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	1,888,733	133,308	647,023	489,366	31,457	587,580	–	587,580
Proved Plus Probable Reserves	4,162,266	340,099	1,387,685	853,490	49,595	1,531,396	252,863	1,278,533

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⁾	25,713	13.83	2.31
	Conventional Natural Gas ⁽²⁾	37,169	3.92	0.65
	Shale Natural Gas	168,925	4.01	0.67
	Total	231,807	4.33	0.72
Proved Plus Probable Reserves	Light and Medium Oil ⁽¹⁾	37,401	12.93	2.15
	Conventional Natural Gas ⁽²⁾	72,763	3.89	0.65
	Shale Natural Gas	341,427	4.07	0.68
	Total	451,591	4.28	0.71

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.

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.

Advisories & Contact

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 and 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

The press release contains references to terms commonly used in the oil and gas industry.

Total revenue is a non-GAAP term 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 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.

Operating and cash netback is not defined by IFRS in Canada and is referred to as a non-GAAP measure. 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.

FD&A costs and F&D costs have been calculated in accordance with NI 51-101. F&D costs refers to all current year net capital expenditures, excluding property acquisitions and dispositions with associated reserves, and including changes in FDC on a proved or proved plus probable basis. FD&A costs incorporate both costs and associated reserve additions related to acquisitions net of any dispositions during the year. 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 as a measure to assess the performance of the Company’s resources required to locate and extract new hydrocarbon reservoirs. 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. FD&A and F&D 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.

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.

This news 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 2017 the ratio between the average price of West Texas Intermediate (“WTI”) crude oil at Cushing and NYMEX natural gas was approximately 17:1 (“Value Ratio”). The Value Ratio is obtained using the 2017 WTI average price of $50.81 (US$/Bbl) for crude oil and the 2017 NYMEX average price of $3.02(US$/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.

SOURCE Cequence Energy Ltd.

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