Cona Resources Ltd. Announces Fourth Quarter & Year-End 2017 Results and Revised 2018 Guidance

CALGARY, March 6, 2018 /CNW/ - Cona Resources Ltd. ("Cona" or the "Company") (TSX: CONA) announces its operating and financial results for the three months and year ended December 31, 2017 and revised guidance for 2018 reflecting recent asset dispositions and continued weakness in Canadian heavy oil prices.

Cona's financial statements, management's discussion and analysis ("MD&A") and annual information form ("AIF") for the year ended December 31, 2017, as well as the news release dated February 21, 2018 announcing our 2017 year-end reserves information, are available on our website at www.conaresources.com and on SEDAR at www.sedar.com.

FINANCIAL AND OPERATING HIGHLIGHTS

		Three months ended			Year ended
($000s, except per share figures and unless otherwise noted)		December 31, 2017	September 30, 2017	December 31, 2016	December 31, 2017	December 31, 2016
Financial
Oil and natural gas sales		99,104	84,839	94,072	368,084	308,754
Funds from operations^(1)		27,882	25,347	40,179	89,869	134,980
	Per share – diluted	0.27	0.25	0.32	0.86	1.11
Net loss		(108,295)	(6,440)	(120,531)	(86,996)	(196,213)
	Per share – basic	(1.07)	(0.05)	(0.99)	(0.85)	(1.66)
	Per share – diluted	(1.07)	(0.05)	(0.99)	(0.85)	(1.66)
Net debt^(1)		332,958	344,273	252,348	332,958	252,348
Dividends declared		-	2,020	12,229	14,590	54,397
	Per share	-	0.02	0.10	0.14	0.46
Capital expenditures		15,446	7,782	14,889	57,932	51,445
Dispositions		-	1,488	73,266	1,698	72,954
Weighted average shares outstanding (000s)
	Basic	101,006	101,006	121,914	102,951	117,955
	Diluted	102,575	101,006	126,484	105,037	121,792
Shares outstanding at period end (000s)		101,006	101,006	123,506	101,006	123,506
Operating
Average daily production
	Heavy oil (bbl/d)	16,556	17,297	17,524	16,953	17,476
	Light oil & NGL (bbl/d)	-	-	399	-	538
	Natural gas (mcf/d)	1,099	1,854	2,146	1,520	2,358
	Total (boe/d)	16,739	17,606	18,281	17,206	18,407
		Three months ended			Year ended
		December 31, 2017	September 30, 2017	December 31, 2016	December 31, 2017	December 31, 2016
Average realized price
	Heavy oil ($/bbl)^(2)	50.38	45.70	43.16	46.68	35.27
	Light oil & NGL ($/bbl)	-	-	55.03	-	46.16
	Oil & NGL ($/bbl)	50.38	45.70	43.42	46.68	35.59
	Natural gas ($/mcf)	2.95	1.85	2.97	2.50	2.01
	Combined ($/boe)	50.03	45.08	42.93	46.22	35.09
Netbacks ($/boe)
	Average realized price^(2)	50.03	45.08	42.93	46.22	35.09
	Royalties	(5.18)	(4.53)	(4.58)	(4.86)	(3.69)
	Production and operating expenses	(17.55)	(17.36)	(15.42)	(17.37)	(15.91)
	Transportation expenses	(2.16)	(1.97)	(1.97)	(2.14)	(1.82)
	Operating netback^(1)	25.14	21.22	20.96	21.85	13.67
	Realized gains (losses) on financial derivative contracts	(2.34)	0.83	8.84	(0.62)	13.97
	General and administrative expenses^(3)	(2.14)	(1.90)	(2.76)	(2.82)	(3.22)
	Cash finance costs	(3.43)	(3.50)	(3.96)	(3.89)	(4.30)
	Other	0.40	(0.74)	0.52	(0.20)	0.05
	Funds from operations^(1)	17.63	15.91	23.60	14.32	20.17

Notes:
(1)	"Funds from operations", "net debt" and "operating netback" do not have any standardized meaning prescribed by International Financial Reporting Standards. See "Non-IFRS Measures".
(2)	Average realized oil prices are net of blending expenses and include the impact of physical delivery contracts (when applicable).
(3)	General and administrative expenses for 2017 includes $4.4 million ($4.0 million of termination payments and $0.4 million of other costs) or $0.69/boe related to the change of control that occurred in May 2017.

MESSAGE TO SHAREHOLDERS

The Cona team demonstrated the true potential of the Company's asset base through 2017 as we achieved essentially flat year-over-year production, after adjusting for the dispositions in the fourth quarter of 2016, while re-investing only 64% of our funds from operations. We achieved very competitive finding, development and acquisition ("FD&A") measures leading to strong recycle ratios of over six times on a proved plus probable basis, based on our 2017 operating netback. We are pleased to deliver strong results in a period of challenging commodity prices.

As we begin 2018, we face a number of headwinds. In November 2017, the Keystone Pipeline System was taken out of service for 12 days resulting in limited take-away capacity for oil volumes from Western Canada. The over-supply of oil volumes resulted in a spike in the spot WTI to Western Canada Select (WCS) differential that reached as high as US$30/bbl. While we are encouraged by recent movement in the forward curves suggesting the WTI/WCS differential will improve later in 2018, Cona is proactively providing 2018 guidance that reflects how the Company will navigate a sustained, wider WTI/WCS differential. We have executed our first quarter 2018 capital program as planned, but have reduced our capital expenditure outlook for 2018 to $44.5 million from $61.5 million with a corresponding estimated production impact of 450 boe/d across the year. With the nature of Cona's asset base and capital program, the Company is well positioned to execute quickly on the projects consistent with the initial budget should the WTI/WCS differential continue to improve. Subsequent to year-end, Cona completed two non-core asset sales and one asset exchange as part of our asset disposition program. These transactions reduced our forecast for 2018 average daily production by approximately 650 boe/d with minimal impact on funds from operations.

FOURTH QUARTER & ANNUAL 2017 HIGHLIGHTS

• Annual 2017 production of 17,206 boe/d (99% oil) resulted in annual production per share increasing by 8% over 2016.
  
  
• Production per share in the fourth quarter of 2017 increased by 13% as compared to the same period in 2016. Average fourth quarter production of 16,739 boe/d was impacted by severe winds and unusually wet weather early in the quarter. December volumes recovered to an average of 17,060 boe/d, on target for the month.
  
  
• Funds from operations were $27.9 million ($0.27 per common share) for the fourth quarter of 2017 and $89.9 million ($0.86 per common share) for 2017.
   
  
• Capital expenditures for 2017 totalled $57.9 million, which included the drilling of 70 (67.0 net) wells. Development in 2017 was focused primarily in the Cactus Lake and Winter areas.
  
  
• 2017 FD&A costs were favorable for an oil weighted asset base at $3.54 per boe for proved plus probable ("2P") reserves, $7.01 per boe for proved ("1P") reserves and $6.58 per boe for proved developed producing ("PDP") reserves, including future development capital.
  
  
• Strong 2017 FD&A costs resulted in favorable recycle ratios of over three times for PDP and 1P reserves and over six times for 2P reserves, based on a 2017 operating netback of $21.85 per boe.
  
  
• General and administrative expenses for 2017, excluding the change of control costs of $4.4 million, were $2.13/boe, down 34% from 2016.
  
  
• Operating netbacks for the fourth quarter of 2017 of $25.14 per boe continue to be strong despite relatively weak commodity prices and widening heavy oil differentials.
  
  
• In 2017, Cactus Lake, Court and Winter achieved a combined field operating income of $129.9 million and free cash flow of $76.8 million. Combined production for these three properties grew by 4% in 2017 compared to 2016.
  
  
• Net debt at December 31, 2017 of $333.0 million decreased by $11.3 million as compared to September 30, 2017. Cona has a $325.0 million credit facility with over 40% undrawn at year-end.
  
  
• During the third quarter of 2017, Cona purchased all of its outstanding US$269.7 million senior unsecured notes. The purchase was financed with our existing credit facility, a new $160.0 million second lien term loan and cash on hand, resulting in all of our debt denominated in Canadian dollars. Historically, fluctuations in the CAD/USD exchange rate triggered significant foreign currency gains and losses which contributed to volatility in earnings. Additionally, Cona's current debt structure provides the flexibility to adjust borrowing levels, whereas the senior notes did not.

OPERATIONS REVIEW

All of Cona's producing properties are located in southwest Saskatchewan. Approximately 90% of Cona's production is under natural water drive, waterflood, polymer flood or steam assisted gravity drainage ("SAGD"), which supports our best-in-class base corporate decline rate of approximately 12%. Over 78% of the Company's fourth 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. Cona operates and has a 100% working interest in the property, which produces from the Basal Mannville and Bakken formations.

Cactus Lake fourth quarter and annual 2017 production averaged 8,483 boe/d and 8,596 boe/d, respectively. As a result of the debottlenecking operation completed in May 2017, Cona increased injection rates to the highest historical levels and oil production is responding favorably.

Results from 37 wells drilled in 2017 are in line with management's expectations. 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.

Impressive operating performance underpins the strong economics achieved at Cactus Lake. For the year ended December 31, 2017, when WTI averaged US$50.95/bbl, Cactus Lake generated $94.5 million of net operating income. During the same period, we invested $31.6 million of capital into the field, including drilling and polymer powder, resulting in $62.9 million of field level free cash flow.

Court

Cona operates and has a 100% working interest in the Court property, which produces largely from the Bakken formation. Fourth quarter and annual 2017 production at Court averaged 1,584 boe/d and 1,698 boe/d, respectively. Year-over-year production declined less than 10% with only $1.0 million of capital invested and no wells drilled in 2017.

For the year ended December 31, 2017 when WTI averaged US$50.95/bbl, Court generated $11.6 million of net operating income. During the same period, we invested $1.0 million of capital into the field, resulting in $10.6 million of field level free cash flow.

Winter

The Winter property produces from the Basal Mannville Cummings formation. The asset exchange, announced on February 21, 2018, increased our working interest in the Cona-operated Winter property to 100% from an average of 71%.

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.

Fourth quarter and annual 2017 production at Winter averaged 3,010 boe/d and 3,095 boe/d, respectively. Cona drilled 32 (29.0 net) wells during 2017.

Wells Drilled

The following table summarizes the drilling program for the year ended December 31, 2017:

Field	Gross	Net
Cactus Lake	37	37.0
Winter^(1)	32	29.0
Other	1	1.0
Total	70	67.0
Note:
(1)       There were 2.0 net service wells drilled at Winter during 2017.

ASSET DISPOSITION PROGRAM

Cona announced an asset disposition program in January 2018. The response has been positive with a number of parties currently engaged in the evaluation of the assets being marketed.  To date, Cona has successfully closed two asset dispositions and one asset exchange for aggregate net proceeds of approximately $10.0 million. As a result of these transactions, Cona now holds a 100% working interest in substantially all of our properties.  The non-core properties disposed had cost structures higher than our corporate average and reduce estimated 2018 production by 650 boe/d with minimal impact on funds from operations.

RISK MANAGEMENT

Cona's risk management strategy includes physical delivery, financial derivative and foreign exchange contracts that is designed to protect realized prices on crude oil volumes. A summary of Cona's current hedge position is provided in the table below.

(C$)^(1,2)		2018	2019
WTI
Hedged volumes (bbl/d)		8,000	2,000
Average price ($/bbl)		65.24	65.00

Notes:
(1)	Contracts denominated in US dollars have been converted to Canadian dollars at CAD/USD daily exchange rate for March 6, 2018.
(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 consolidated financial statements for the years ended December 31, 2017 and 2016.

During the year ended December 31, 2017, Cona realized $3.9 million in losses on financial derivative contracts. Losses on financial derivative contracts were due to narrower than hedged WTI/WCS differentials, partially offset by gains realized on WTI contracts due to actual oil prices that were lower than hedged prices.

GUIDANCE⁽¹⁾

The table and discussion below provides a comparison of Cona's operational guidance and actual results for the year ended December 31, 2017, as well as a summary of Cona's prior and revised operational guidance for the year ended December 31, 2018.

		2017			2018
		Guidance^(2)(3)	Actual	Variance (%)	Prior Guidance^(2)(3)	Revised Guidance^(3)
Production (boe/d)		17,400	17,206	(1)	17,400	16,300
Pricing
	WTI (US$/bbl)	49.60	50.95	3	53.50	60.00
	WTI/WCS differential (US$/bbl)	11.75	11.98	2	13.75	21.50
	CAD/USD exchange rate	1.298	1.298	-	1.280	1.265
	WCS ($/bbl)	49.12	50.54	3	50.88	48.70
	AECO ($/mcf)	2.60	2.16	(17)	2.00	1.30
	Average realized price ($/boe)	45.18	46.22	2	46.84	42.25
Expenses
	Average royalty rate (%)	12	11	(8)	13	13
	Operating ($/boe)	16.50	17.37	5	17.65	17.65
	Transportation ($/boe)	2.20	2.14	(3)	2.15	2.05
	General & administrative ($/boe)^(3)	2.04	2.13	4	2.15	2.20
	Finance and other ($/boe)^(3)	4.06	4.09	2	3.85	4.55
	Change of control costs ($/boe)^(4)	0.70	0.69	(1)	-	-
Funds from operations ($ millions)^(5,6)
	Excluding hedging	94	94	-	97	63
	Including hedging	94	90	(4)	82	32
Funds from operations per boe ($/boe)^(5,6)
	Excluding hedging	14.85	14.94	1	15.20	10.70
	Including hedging	14.90	14.32	(4)	12.90	5.45
Capital expenditures ($ millions)		60	58	(3)	61.5	44.5

Notes:
(1)	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 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. This summary has been approved by management as of the date of this news release.
(2)	The 2017 guidance was provided in a news release dated August 14, 2017 and the prior 2018 guidance was provided in a news release dated November 14, 2017. The news releases are available on Cona's website at www.conaresources.com or on SEDAR at www.sedar.com.
(3)	Average realized prices are calculated based on oil and natural gas sales net of blending expenses.
(4)	Includes termination payments of $4.0 million and other costs of $0.4 million related to the change of control.
(5)	Includes costs related to the change of control (see Note 4).
(6)	"Funds from operations" and "funds from operations per boe" are non-IFRS Measures. See discussion under the heading "Non-IFRS Measures".

2018 Guidance

Cona has revised guidance for 2018 to reflect asset dispositions and an operational plan in the event that the recent weakness in Canadian heavy oil prices is sustained.

Our revised guidance for 2018, based on a WTI price of US$60.00/bbl and WTI/WCS differential of US$21.50/bbl, includes production of 16,300 boe/d and funds from operations of $32.0 million ($63.0 million excluding hedging) or $0.32 per common share ($0.62 per common share excluding hedging).

Capital expenditures are forecast to be $44.5 million in 2018, which includes the drilling of 31 gross wells. During the first quarter of 2018, Cona drilled the majority of the wells planned for 2018 including 15 wells at Cactus Lake, 11 wells at Winter and five wells at Court.

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

			Capital ($millions)	Well Count (gross)
EOR development and infill drilling			31.6	15
Other drilling			11.7	16
Corporate and other			1.2	-
Total			44.5	31

Cona operates and controls virtually all of our 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 align spending with the appropriate economic returns.

Conference Call – March 7, 2018

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

Cona will host a conference call tomorrow, March 7, 2018, starting at 9:00am MT (11:00am ET), to review the Company's fourth quarter and year-end 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 March 21, 2018 and can be accessed by dialing 1 [phone] and entering the conference number 1226446 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.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information

This press release contains FD&A costs and recycle ratios, which are metrics commonly used in the oil and natural gas industry.  These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. 

FD&A costs are calculated as the sum of development capital plus acquisition capital plus the change in future development costs for the period divided by the change in total reserves plus production for the period. The aggregate of the exploration, development and acquisition costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for the year.

FD&A recycle ratio is calculated as operating netback per boe divided by finding, development and acquisition costs per boe.

The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

Cona's oil and natural gas reserves statement for the year ended December 31, 2017, which will include complete disclosure of its oil and natural gas reserves in accordance with NI 51-101, is contained within Cona's AIF which is available on Cona's website at www.conaresources.com and on SEDAR at www.sedar.com.

Non-IFRS Measures

In this news release, Cona has used the terms "operating netback", "funds from operations", "funds from operations per boe", "net debt", "free cash flow" and "field level free cash flow", which are referred to as "non-IFRS measures". Management uses "operating netback", "funds from operations", "funds from operations per boe" and "funds from operations per share" in the evaluation of the Company's operating and financial performance and to provide its shareholders with a measure of the Company's efficiency and its ability to generate cash to fund capital expenditures, pay dividends and/or repay debt. Management uses "net debt" to assess the Company's liquidity and general financial strength. "Free cash flow" and "field level free cash flow" are presented to assist management and investors in analyzing operating performance by the business in the stated period.

"Operating netback" is used as an indicator of operating performance and profitability relative to current commodity prices, calculated on a per boe basis.  Operating netback is calculated as oil and natural gas sales (net of blending expenses) less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the period.  There are no IFRS measures that are reasonably comparable to operating netback.

"Funds from operations" is used by the Company to analyze operating performance and its ability to fund capital investments. Funds from operations is calculated as cash flow from operating activities (as determined in accordance with IFRS) before shares purchased for the Incentive Plan, cash settlement of Awards, decommissioning costs incurred, onerous contract provision costs incurred and changes in non-cash operating working capital. Management considers funds from operations to be a key measure of the results generated by its principal business activities before the consideration of how those activities are financed or how the results are taxed and before decommissioning expenditures. Funds from operations should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS.

"Funds from operations per boe" is calculated using funds from operations and boe sales volumes for the period.

"Funds from operations per share" is calculated using funds from operations and the weighted average basic and diluted shares used in calculating net income per share.

"Net debt" is calculated as the principal amount drawn on bank loans, the Term Loan, the Senior Notes (if applicable), the onerous contract provision and working capital (working capital includes cash, accounts receivable, inventory, prepaid expenses and deposits, accounts payable and accrued liabilities and dividends payable), and is used by the Company to assess liquidity and general financial strength. Net debt should not be considered an alternative to, or more meaningful than, current assets or current liabilities as determined in accordance with IFRS.

"Free cash flow" equals funds from operations less capital expenditures.

The following table shows the calculation of "field level free cash flow" for Cactus Lake, Court and Winter for the year ended December 31, 2017:

(C$)		Cactus Lake	Court	Winter
Average realized price ($/boe)		45.10	44.82	43.27
Royalties ($/boe)		(3.44)	(7.27)	(5.33)
Operating costs ($/boe)		(11.46)	(18.73)	(17.06)
Transportation ($/boe)		(0.09)	(0.04)	0.14
Operating netback ($/boe)		30.11	18.78	21.02
Production volumes (boe/d)		8,596	1,698	3,095
Field operating income ($MM)		94.5	11.6	23.7
Capital expenditures ($MM)		31.6	1.0	20.4
Field level free cash flow ($MM)		62.9	10.6	3.3

Non-IFRS measures do not have any standardized meanings prescribed by IFRS and should not, therefore, be considered in isolation or used in substitute for measures of performance prepared in accordance with IFRS. Other issuers may calculate non-IFRS measures differently. Investors should be cautioned that non-IFRS measures should not be construed as alternatives to financial results determined in accordance with IFRS as indicators of the Company's performance. For additional information regarding non-IFRS measures, including reconciliations to measures recognized by IFRS, please refer to heading "Advisories – Non-IFRS Financial Measures" in the MD&A for the years ended December 31, 2017 and 2016, which is available on SEDAR at www.sedar.com.

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 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 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 and production at Cactus Lake, 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 2018;
• Base decline rates and corporate decline rates;
• 2018 funds from operations including and excluding hedging; and
• Company's hedging strategy.

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, 2017. 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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