Cona Resources Ltd. Announces Third Quarter 2017 Results and 2018 Guidance

CALGARY, Nov. 14, 2017 /CNW/ - Cona Resources Ltd. ("Cona" or the "Company") (TSX: CONA) announces its operating and financial results for the three and nine months ended September 30, 2017. Cona's financial statements and management's discussion and analysis ("MD&A") for the three and nine months ended September 30, 2017 are available on our website at www.conaresources.com and on SEDAR at www.sedar.com.

FINANCIAL AND OPERATING HIGHLIGHTS

		Three months ended			Nine months ended
		September 30, 2017	June 30, 2017	September 30, 2016	September 30, 2017	September 30, 2016
Financial  ($000s,except as otherwise noted)
Oil and natural gas sales		84,839	93,110	76,045	268,980	214,682
Funds from operations – normalized^(1,3)		25,347	20,083	34,038	66,343	94,801
	Per share – diluted – normalized	0.25	0.19	0.28	0.63	0.79
Net income (loss)		(6,440)	6,853	(16,775)	21,299	(75,682)
	Per share – basic	(0.06)	0.07	(0.14)	0.21	(0.65)
	Per share – diluted	(0.06)	0.06	(0.14)	0.19	(0.65)
Net debt^(1)		344,273	359,350	335,912	344,273	335,912
Dividends declared		2,020	6,060	14,347	14,590	42,167
	Per share	0.020	0.120	0.120	0.140	0.360
Capital expenditures		7,782	13,674	22,111	42,486	36,869
Dispositions		1,488	-	-	1,698	-
Weighted average shares outstanding (000s)
	Basic	101,006	100,745	118,940	103,607	116,630
	Diluted	101,006	103,194	122,355	105,867	120,240
Shares outstanding at period end (000s)		101,006	101,006	120,445	101,006	120,445
Operating
Average daily production
	Heavy oil (bbl/d)	17,297	16,986	16,924	17,087	17,461
	Light oil & NGL (bbl/d)	-	-	480	-	585
	Natural gas (mcf/d)	1,854	1,762	2,159	1,662	2,429
	Total (boe/d)	17,606	17,280	17,764	17,364	18,451

		Three months ended			Nine months ended
		September 30, 2017	June 30, 2017	September 30, 2016	September 30, 2017	September 30, 2016
Average realized price
	Heavy oil ($/bbl)^(2)	45.70	46.51	38.26	45.43	32,53
	Light oil & NGL ($/bbl)	-	-	49.93	-	44.14
	Oil & NGL ($/bbl)	45.70	46.51	38.59	45.43	32.91
	Natural gas ($/mcf)	1.85	2.85	2.26	2.40	1.72
	Combined ($/boe)	45.08	46.01	38.08	44.93	32.41
Netbacks ($/boe)
	Average realized price	45.08	46.01	38.08	44.93	32.41
	Royalties	(4.53)	(5.06)	(4.23)	(4.76)	(3.39)
	Production and operating expenses	(17.36)	(18.87)	(17.26)	(17.30)	(16.08)
	Transportation expenses	(1.97)	(2.18)	(2.03)	(2.13)	(1.77)
	Operating netback^(1)	21.22	19.90	14.56	20.74	11.17
	Realized gains (losses) on financial derivative contracts	0.83	(0.28)	13.44	(0.04)	15.72
	General and administrative expenses	(1.90)	(2.13)	(2.87)	(2.13)	(3.38)
	Cash finance costs	(3.50)	(4.41)	(4.39)	(4.04)	(4.42)
	Change of control costs^(4)	-	(2.77)	-	(0.93)	-
	Other	(0.74)	(0.29)	0.47	(0.41)	(0.11)
	Funds from operations^(1)	15.91	10.02	21.21	13.19	18.98
	Add back change of control costs	-	2.77	-	0.93	-
	Funds from operations – normalized^(1,3)	15.91	12.79	21.21	14.12	18.98

Notes:
(1)	Funds from operations, funds from operations – normalized, net debt and operating netback do not have any standardized meaning prescribed by International Financial Reporting Standards. See "Non-IFRS Financial Measures" in the MD&A for the three and nine months ended September 30, 2017 and 2016.
(2)	Average realized oil prices are net of blending expenses and include the impact of physical delivery contracts (when applicable).
(3)	Funds from operations is normalized for change of control costs (see note 4).
(4)	Includes termination payments of $4.0 million and other costs of $0.4 million related to the change of control that occurred in May 2017.

MESSAGE TO SHAREHOLDERS

Cona has achieved a number of milestones following the change of control in May 2017. We recently welcomed our new President & CEO, Rob Morgan, and during the third quarter of 2017 we refinanced the US dollar denominated senior unsecured notes.

"I am excited to be part of the Cona team and to lead the organization in unlocking the value of the Company's large oil-in-place assets with the potential to generate significant free cash flow over the longer term. This is an exciting time for Cona as we focus on capital discipline, cost structure and application of technology in the pursuit of value creation," said Mr. Morgan. "Cona is also extremely well positioned to capitalize on new growth opportunities given our highly competent and dedicated team, our supportive lending group and our strong board of directors."

With our corporate structure now simplified and our strategic direction clear and aligned, Cona will seek to take advantage of our industry leading low corporate decline rate of 10-12% as we move forward with our plan for 2018. Cona's successful enhanced oil recovery projects remain a cornerstone of the Company's ability to maintain production levels with capital expenditures less than the forecasted 2018 funds from operations. While our current 2018 plan contemplates maintaining production volumes at existing levels with $61.5 million of development capital, our team will work to improve the Company's ability to generate additional free cash flow that can be used to repay debt as a priority, or in combination with production growth if supported by compelling economics.

HIGHLIGHTS

• Production was 17,606 boe/d (98% oil) for the third quarter of 2017, slightly ahead of our second quarter of 17,280 boe/d. We expect production for the year ending December 31, 2017 to be within our guidance of 17,400 boe/d.
  
  
• Operating costs for the third quarter of 2017 were $17.36 per boe, reflecting ongoing surface maintenance activities. Cona is expecting annual operating costs to be consistent with year-to-date actual results in the order of $17.30 per boe.
  
  
• Operating netbacks for the third quarter of 2017 of $21.22 per boe continue to be strong despite relatively weak commodity prices as we benefitted from tight heavy oil differentials.
  
  
• Capital expenditures for the third quarter of 2017 were modest at $7.8 million. This included the drilling of one gross (1.0 net) well, polymer powder, well workovers and facilities expenditures. Cona anticipates executing a fourth quarter drilling program at Cactus Lake and Winter that will bring our 2017 capital expenditures in line with guidance of $60.0 million.
  
  
• Funds from operations were $25.3 million ($0.25 per common share – diluted) for the third quarter of 2017 with a corresponding total payout ratio of 41%. Total payout ratio is calculated as capital expenditures plus dividends paid divided by funds from operations.
  
  
• During the third quarter of 2017, Cona purchased all of its outstanding US$269.7 million senior unsecured notes. The purchase was financed with the existing credit facility, a new $160.0 million second lien term loan and cash on hand. Our debt is now denominated in Canadian dollars, eliminating the exposure to foreign currency risk and providing us with increased financial flexibility toward our immediate goal of reducing leverage.
  
  
• Cona completed the quarter with net debt of $344.3 million, a decrease of $15.1 million from the prior quarter-end. Net debt to trailing four quarters funds from operations, normalized for change of control costs, was 3.2x.
  
  
• On October 31, 2017, our credit facility was increased to $325.0 million from $285.0 million. At September 30, 2017, Cona had $185.8 million drawn on its credit facility.

OPERATIONS REVIEW

All of Cona's producing properties are located in southwest Saskatchewan and approximately 90% of Cona's production is associated with either an active waterflood or a natural water drive reservoir. Over 75% of the Company's third quarter 2017 production was from three fields: Cactus Lake, Winter and Court.

Cactus Lake

Cactus Lake is Cona's largest field by production and reserves. The property is 100% owned and operated by Cona and produces from the Basal Mannville and Bakken formations. Since Cona acquired the property in 2010, we have commenced an infill drilling program to reduce well spacing to 10 acres from 40 acres, optimized the waterflood and initiated a polymer flood which has been sequentially staged across the reservoir following the infill drilling program. We have drilled over 450 wells to date and have 375 potential infill drilling opportunities at 10 acre spacing (internal estimate) of which 238 drilling locations have been booked to proved plus probable ("2P") reserves (per independent reserves evaluator). Base decline rates (excluding production from new wells drilled in the last 12 months) are at or near zero in this field due to favorable waterflood and polymer flood response.

Cactus Lake third quarter production averaged 8,775 boe/d, a record high for this field. As a result of the debottlenecking operation completed in May 2017, Cona has achieved the highest injection rates to date and oil production is responding favorably. Results from wells drilled in 2017 are in-line with management's expectations. Cona has budgeted to drill 37 wells in 2017 at Cactus Lake, with 25 wells drilled as of September 30, 2017. We have budgeted to drill 20 wells at Cactus Lake in 2018. Field economics support management's near-term plan to expand the polymer flood.

Impressive operating performance underpins the strong economics achieved at Cactus Lake. For the first nine months of 2017 when WTI averaged US$49.47/bbl, Cactus Lake generated $68.8 million of net operating income. During the same period, we invested $22.9 million of capital into the field, including drilling and polymer powder, resulting in $45.9 million of field level free cash flow.

Winter

The Winter property produces from the Basal Manville Cummings formation. The Company holds an average 74% working interest (based on 2P reserves) and operates 99% of the production. Since Cona acquired the property in 2010, we initiated a drilling program to reduce the horizontal well spacing to approximately 25 meters from 100 meters. The Winter formation is unique in having excellent reservoir quality (with permeability in excess of five Darcies in the heart of the channel system) and an underlying aquifer that provides ongoing pressure support to an oil column that is up to 18 meters thick. Horizontal wells placed near the top of the oil column collect oil swept by the aquifer. We have drilled over 230 (185.0 net) wells at Winter and have 419 gross (296.0 net) potential infill drilling opportunities (internal estimate) of which 314 gross (227.0 net) drilling locations have been booked to 2P reserves (per independent reserves evaluator).

In 2017, Cona began transitioning to longer horizontal wells with lateral lengths of over 600 meters. While these wells cost an incremental 5% as compared to the shorter lateral horizontal wells drilled previously, the overall economics are expected to exceed the incremental cost.

At Winter, production in the third quarter of 2017 averaged 3,300 boe/d, a 9% increase over the second quarter. Cona has budgeted to drill 32 (28.7 net) wells in 2017, with 25 (22.6 net) wells drilled as of September 30, 2017. We plan to drill 23 (18.0 net) wells at Winter in 2018.

Court

The Court property is 100% owned and operated by Cona and produces largely from the Bakken formation. We have drilled approximately 120 wells since 2010 and have 90 potential drilling opportunities (internal estimate) of which 40 drilling locations have been booked to 2P reserves (per independent reserves evaluator).

During 2017, Cona was able to curtail the base decline rate to 3% from 10% through ongoing optimization of the waterflood. At Court, production in the third quarter of 2017 averaged 1,730 boe/d. Cona has budgeted to drill five wells at Court in 2018 and continue with waterflood optimization.

Wells Drilled

The following table summarizes the drilling program for the first nine months of 2017:

Field			Gross	Net
Cactus Lake			25	25.0
Winter^(1)			25	22.6
Luseland			1	1.0
Total			51	48.6

Note:
(1)	There was 1.0 net service well drilled at Winter during the first nine months of 2017.

RISK MANAGEMENT

Cona has a comprehensive hedging program in place to protect prices on crude oil volumes and maintain the Company's strong financial position. A summary of Cona's current hedge position is provided in the table below.

(C$)^(1,2)			2017	2018
WTI
	Hedged volumes (bbl/d)		8,000	7,000
	Average price ($/bbl)		68.07	62.63
WTI / WCS differential
	Hedged volumes (bbl/d)		8,000	-
	Average price ($/bbl)		14.41	-

Notes:
(1)	Contracts denominated in US dollars have been converted to Canadian dollars at CAD/USD strip prices as of November 9, 2017.
(2)	The prices and volumes in this table represent averages for several contracts over the respective periods presented. The average price of a group of contracts is for indicative purposes only and does not have the same settlement profile as the individual contract. Details of the risk management contracts are disclosed in the notes to the Company's September 30, 2017 condensed consolidated interim financial statements.

During the nine months ended September 30, 2017, Cona realized $0.2 million in losses on financial derivative contracts. The losses realized were mainly on narrower than hedged WTI/WCS differentials, partially offset by gains realized on WTI contracts due to weaker than hedged oil prices. Cona is focused on using hedges to support our base development economics and will target to hedge at or above budgeted prices in any given year.

GUIDANCE

The guidance provided is based on a number of material assumptions and factors set out below and under the heading "Forward-Looking Statements". This financial outlook is included to provide readers with an understanding of the Company's operations for 2017 and 2018. Readers are cautioned that the information may not be appropriate for other purposes. The actual results of Cona's operations for the corresponding period will vary from the financial outlook and such variations may be material. See "Forward-Looking Statements" for a discussion of the risks that could cause actual results to vary.

The table below provides a summary of Cona's operational guidance for the year ending December 31, 2017 with a comparison to results for the nine months ended September 30, 2017, as well as a summary of Cona's operational guidance for the year ending December 31, 2018.

		2017			2018
		Guidance^(1)		YTD Actual	Guidance^(1)
Production (boe/d)		17,400		17,364	17,400
Pricing
	WTI (US$/bbl)	49.60		49.47	53.50
	WCS differential (US$/bbl)	11.75		11.88	13.75
	CAD/USD exchange rate	1.298		1.307	1.280
	WCS ($/bbl)	49.12		49.09	50.88
	AECO ($/mcf)	2.60		2.31	2.00
Expenses
	Average royalty rate (%)	12		11	13
	Operating ($/boe)	16.50		17.30	17.65
	Transportation ($/boe)	2.20		2.13	2.15
	Corporate costs ($/boe)^(2)	6.10		6.58	6.00
	Change of control costs ($/boe)^(3)	0.70		0.93	-
Excluding hedging
	Funds from operations ($ millions)^(4,5)	94		62	97
	Funds from operations per boe ($/boe)^(4,5)	14.85		13.23	15.20
Including hedging
	Funds from operations ($ millions)^(4,5)	94		62	82
	Funds from operations per boe ($/boe)^(4,5)	14.90		13.19	12.90
Capital expenditures ($ millions)		60		40.8	61.5
Total payout ratio (%)^(4,5)		78		93	75

Notes:
(1)	Represents 2017 guidance provided in a news release dated August 14, 2017 and 2018 guidance provided in news release dated November 14, 2017. The news releases are available on Cona's website at www.conaresources.com or at www.sedar.com.
(2)	Corporate costs include general and administrative expenses, cash finance costs and other cash items.
(3)	Includes termination payments of $4.0 million and other costs of $0.4 million related to the change of control that occurred in May 2017.
(4)	Includes change of control costs (see note 3).
(5)	Non-IFRS measure – see discussion under the heading "Non-IFRS Measures".

Cona's 2018 budget is largely focused on the Company's inventory of enhanced oil recovery projects supported by infill drilling projects that improve overall recovery factors. The capital breakdown is summarized as follows:

			Capital ($millions)	Well Count (gross)
EOR development and infill drilling			42.0	29
Other drilling			16.0	25
Corporate and other			3.5	-
Total			61.5	54

Cona operates and controls virtually all of its development program, which provides flexibility in our capital expenditures. We will continue to review and evaluate our capital spending program in light of commodity prices and will align spending with the appropriate economic returns.

Conference Call Today

9:00am MT (11:00am ET)

Cona will host a conference call today, November 14, 2017, starting at 9:00am MT (11:00am ET), to review the Company's third quarter 2017 results. Participants can access the conference call by dialing [phone] or toll-free (US & Canada) 1 [phone] and entering the passcode 98589.

A recording of the conference call will be available until November 28, 2017 and can be accessed by dialing 1 [phone] and entering the conference number 1223086 and passcode 98589. The replay will be available approximately one hour following completion of the call. The conference call recording will also be available on Cona's website at www.conaresources.com.

ADVISORIES

BOE Conversion and Other Advisories

In this news release, natural gas has been converted to boe based on a conversion rate of six thousand cubic feet of natural gas to one barrel (6 mcf : 1 bbl), which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

Base decline rate is the estimated trend of the Company's production profile. To appropriately determine the trend, a sufficient amount of production data is required and the data cannot include new development (i.e. production from new wells). New development needs to be excluded as the drilling of new wells would increase production volumes. Decline rates are often calculated by vintage (i.e. for each year), which eliminates production increases from development in subsequent years.

Unless otherwise indicated, all currency is in Canadian dollars.

Non-IFRS Measures

This news release makes reference to the non-IFRS measures "funds from operations - normalized", "funds from operations", "field level free cash flow" and "free cash flow", which should not be considered as alternatives to, or more meaningful than, "cash flow - operating activities" as determined in accordance with IFRS. Field level free cash flow and free cash flow are presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures. Funds from operations is defined in "Non-IFRS Financial Measures" in the MD&A for the three and nine months ended September 30, 2017 and 2016.

The following table shows the calculation of field level free cash flow for Cactus Lake for the nine months ended September 30, 2017:

(C$)		Cactus Lake
Average realized price ($/boe)		44.02
Royalties ($/boe)		(3.31)
Operating costs ($/boe)		(11.43)
Transportation ($/boe)		(0.10)
Operating netback ($/boe)		29.18
Production volumes (boe/d)		8,636
Field operating income ($MM)		68.8
Capital expenditures ($MM)		22.9
Field level free cash flow ($MM)		45.9

Forward-Looking Statements

This news release contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking statements") within the meaning of applicable Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements contain words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should", or similar words suggesting future outcomes.

In particular, this news release contains forward-looking statements pertaining to the following:

• Business plans and strategies;
• Capital expenditures for 2017 and 2018;
• Methods and ability to finance operations, capital expenditure programs and working capital requirements;
• The free cash flow potential of the Company's assets;
• The Company's ability to capitalize on future growth opportunities;
• Percentage budgeted annual cash flow for 2018 required to maintain production at current levels;
• Anticipated oil and natural gas production levels in 2017 and 2018;
• Impacts of Cona's transition to horizontal wells with lateral lengths of over 600 meters;
• Plans to expand polymer flooding at Cactus Lake;
• 2018 drilling plans at Court and Winter;
• Future oil and natural gas prices;
• Future costs including operating, transportation, cash finance costs, corporate and change of control costs and royalty rates for 2017 and 2018;
• Base decline rates and corporate decline rates;
• 2017 and 2018 total payout ratios; and
• 2017 and 2018 funds from operations including and excluding hedging.

In addition, 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 reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the difference may be material and adverse to the Company and its shareholders.

With respect to forward-looking statements contained in this news release, management has made assumptions regarding future production levels; future oil and natural gas prices; future operating costs; timing and amount of capital expenditures; the ability to obtain financing on acceptable terms; availability of skilled labour and drilling and related equipment; general economic and financial market conditions; continuation of existing tax and regulatory regimes; and the ability to market oil and natural gas successfully to current and new customers. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties (both general and specific) and risks that the goals or figures contained in forward-looking statements will not be achieved. These factors include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent, general economic, market and business conditions, substantial capital requirements, uncertainties inherent in estimating quantities of reserves and resources, extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time, the need to obtain regulatory approvals on projects before development commences, environmental risks and hazards and the cost of compliance with environmental regulations, aboriginal claims, inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions, potential cost overruns, variations in foreign exchange rates, diluent supply shortages, competition for capital, equipment, new leases, pipeline capacity and skilled personnel, credit risks associated with counterparties, the failure of the Company or the holder of licenses, leases and permits to meet requirements of such licenses, leases and permits, reliance on third parties for pipelines and other infrastructure, changes in royalty regimes, failure to accurately estimate decommissioning costs, inaccurate estimates and assumptions by management, effectiveness of internal controls, the potential lack of available drilling equipment and other restrictions, failure to obtain or keep key personnel, title deficiencies with the Company's assets, geo-political risks, risks that the Company does not have adequate insurance coverage, risk of litigation and risks arising from future acquisition activities. The foregoing risks and other risks are described in more detail in the Company's annual information form for the year ended December 31, 2016. Readers are cautioned that these factors and risks are difficult to predict and that the assumptions used in the preparation of such information, although considered reasonably accurate at the time of preparation, may prove to be incorrect. Accordingly, readers are cautioned that the actual results achieved may vary from the information provided herein and the variations could be material. Readers are also cautioned that the foregoing list of factors is not exhaustive. Consequently, there is no representation by the Company that actual results achieved will be the same in whole or in part as those set out in the forward-looking statements. Furthermore, the forward-looking statements contained in this news release are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

SOURCE Cona Resources Ltd.

about Cona Resources Ltd., please visit our website at www.conaresources.com or contact: Cona Resources Ltd., Telephone: [phone], Rob Morgan, President & Chief Executive Officer; Michael Makinson, Vice President, Finance & Chief Financial Officer

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