Cona Resources Ltd. Announces Second Quarter 2017 Results

FINANCIAL AND OPERATING HIGHLIGHTS

HIGHLIGHTS

• Production was 17,280 boe/d (99% oil) for the second quarter of 2017.
• Production rates continue to benefit from enhanced oil recovery initiatives at Cactus Lake. In the second quarter of 2017, Cona completed a facilities debottlenecking project that has successfully increased polymer injection rates. Near term oil response has been positive and these improvements in field injection rates are expected to continue to enhance future production levels.
• At Winter, Cona has drilled several long horizontal wells. Production response to date has exceeded management’s original type curve by over 30%.
• Operating costs for the second quarter of 2017 were $18.87 per boe. Operating costs in the second quarter of the year tend to be higher as a result of spring break-up conditions and regularly scheduled turnarounds. In addition, operating costs were impacted by the Cactus Lake facilities debottlenecking project, increased power usage and higher downhole maintenance due to an increase in the number of well servicing events.
• Operating netbacks for the second quarter of 2017 of $19.90 per boe continue to be strong despite weak commodity prices.
• Capital expenditures for the second quarter of 2017 totalled $13.7 million. Cona drilled nine gross (9.0 net) wells during the quarter.
• Cona declared dividends totalling $6.1 million ($0.06 per common share) in the second quarter of 2017.
• Funds from operations normalized for the change of control costs were $20.1 million ($0.19 per common share – diluted) for the second quarter of 2017 with a corresponding total payout ratio of 98%. Total payout ratio is calculated as dividends paid plus capital expenditures divided by funds from operations.
• Cona completed the quarter with net debt of $359.4 million and no amount drawn on its $285.0 million credit facility. Net debt to trailing four quarters funds from operations, normalized for change of control costs, was 3.1x.

CHANGE OF CONTROL

On May 11, 2017, affiliates of Waterous Energy Fund (“WEF”) acquired the common shares of the Company held by NGP IX Northern Blizzard S.àr.l. and R/C Canada Coöperatief U.A.. The purchase represented 67% of the Company’s outstanding shares and a change of control of the Company as defined in the senior unsecured notes (“Senior Notes”) indenture and our long-term incentive plan (“Incentive Plan”).

As a result of the change of control, Cona offered to purchase all outstanding Senior Notes totaling US$269.7 million at a price equal to 101% of the principal amount of the notes (the “Refinancing”) together with accrued and unpaid interest. On July 31, 2017, Cona purchased US$262.2 million principal of Senior Notes from holders that accepted the tender offer. The purchase of the Senior Notes plus accrued and unpaid interest totaled US$274.4 million (CAD$345.2 million) and was financed through a draw of $186.8 million on the Company’s existing credit facility, a new $160.0 million second lien term loan (“Term Loan”) entered into for the purposes of financing the tender offer and cash on hand. The July 31, 2017 purchase was completed at a CAD/USD exchange rate of 1.258, which is close to the strongest exchange rate the Canadian currency has traded relative to the US dollar in two years.

According to the terms of the Senior Notes indenture, the Company notified holders of the remaining US$7.5 million Senior Notes that on August 31, 2017 it will redeem all outstanding Senior Notes at a purchase price equal to 101% of the principal amount plus accrued and unpaid interest.

The $160.0 million Term Loan matures on July 28, 2020, and is repayable at par during the first year, 102.5% during the second year and 105.0% during the third year. The interest rate on the Term Loan during the first year is the Canadian Dollar Offered Rate (“CDOR”) plus 7.5% and CDOR plus 10.0% thereafter. A duration fee of 1.0% is payable based on the outstanding amount of the Term Loan on January 29, 2018.

Also as a result of the change of control, all awards outstanding under the Incentive Plan (“Awards”) and certain termination payments became payable. Cona settled 4.4 million Awards for total consideration of $14.9 million with a combination of cash and common shares purchased in the open market. Termination payments of $4.0 million were incurred and recorded as change of control costs.

DEBT REDUCTION AND SUSPENSION OF DIVIDEND

As a result of the Refinancing, all of Cona’s debt will be denominated in Canadian dollars, eliminating the foreign currency risk that the Company was previously exposed to. In addition, the Company’s annual cash finance costs are expected to be lower than prior to the Refinancing and the Company can reduce debt levels at its option. We intend to pay down the Term Loan through a combination of free cash flow and proceeds from the sale of non-core properties. Under current commodity prices, the Company expects to be able to repay the Term Loan prior to its maturity using only free cash flow. To accelerate debt repayment, the Company is suspending its dividend after the dividend payment on August 15, 2017.

Commenting on the Refinancing, Chairman Adam Waterous said, “The refinancing of Cona’s balance sheet is the first step in our plan to reshape Cona to take advantage of its industry leading free cash flow generation, driven by its world class Cactus Lake asset. We are pleased that this refinancing eliminates debt related foreign exchange risk, lowers future cash finance costs and allows the Company to begin reducing leverage immediately. While Cona’s long life reserves and significant free cash flow make it ideal in the medium term to sustain a large dividend, in the short term, we want to take advantage of our new opportunity as a result of this refinancing to pay down debt. Consequently, we are suspending the dividend and redirecting the cash flow to strengthen our balance sheet, while maintaining our highly economic capital program.”

OPERATIONS REVIEW

Capital spending during the second quarter of 2017 was $13.7 million. This included the drilling of nine gross (9.0 net) wells, polymer powder, well workovers and facilities expenditures.

At Cactus Lake, average production for the second quarter increased approximately 2% to 8,516 boe/d compared to average production in the same period of 2016 of 8,366 boe/d. Production from Cactus Lake is approximately 50% of Cona’s total production. Base decline rates (excluding new wells that were drilled) are at or near zero in this field as a result of waterflood and polymer flood pressure support. Production from wells drilled in 2017 is in-line with management’s expectations. In the second quarter of 2017, we completed a facilities debottlenecking project which has successfully increased polymer injection rates. Near term oil response has been positive and these improvements in field injection rates are expected to continue to enhance future production levels.

Impressive operating performance underpins the strong economics being achieved at Cactus Lake. For the first six months of 2017 when WTI averaged US$50.10/bbl, Cactus Lake generated $45.1 million of net operating income. During the same period, we invested $18.8 million of capital into the field, including drilling and polymer powder, resulting in $26.3 million of field level free cash flow.

At our Winter property, we drilled nine gross (9.0 net) wells during the second quarter of 2017. Horizontal wells have been utilized to develop the property as there is water underlying the thick oil column. Similar to Q1 2017, Cona continued to drill a portion of the wells with longer horizontal lengths.  Of the nine gross wells drilled, six averaged lateral lengths of over 600 meters. Subsequent to Q2 2017, production from the 2017 drilling program has reached rates in excess of 1,000 bbl/d net, exceeding budget expectations. Average drilling, completion and equipping costs for the 2017 program is estimated at $615,000 per well.

We continue to focus on decline rates and generating free cash flow. Decline rates are a key driver in determining the capital required to maintain production levels. 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 second quarter 2017 production is from three fields: Cactus Lake, Winter and Court. Cona’s successful EOR projects have resulted in industry leading overall corporate decline rates of 10 – 12%. We estimate that only 50% of budgeted annual cash flow for 2017 is required to maintain production at current levels. The remaining 50% is free cash flow that can be used to grow production and reserves, repay debt or for other corporate initiatives.

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.

During the six months ended June 30, 2017, Cona realized $1.5 million in losses on financial derivative contracts.  The losses realized were mainly on Canadian dollar WTI contracts due to higher than hedged oil prices, partially offset by wider than hedged WTI/WCS differentials.

GUIDANCE

Cona has updated its annual 2017 guidance for the change of the control that occurred during the second quarter of 2017 and lower oil prices. We note there are variations between the actual results for the first half of 2017 and the annual estimates due to the nature of operations over the course of a year. The table below provides a revised summary of Cona’s operational guidance for the year-ended December 31, 2017 with a comparison to the prior guidance and to results for the six months ended June 30, 2017.

Annual production guidance was increased to 17,400 boe/d from 17,100 boe/d as production is exceeding management’s estimates.

Annual guidance for operating cost per boe was increased to $16.50/boe from $15.40/boe to incorporate increased power usage, increased downhole maintenance costs due to a higher number of well servicing events and the Cactus Lake facilities debottlenecking project.

Guidance for annual corporate costs increased slightly to $6.10/boe from $5.70/boe as purchases of Senior Notes assumed in the original guidance during the first half of 2017 were not made as expected.  Revised guidance reflects a purchase of US$6.5 million of Senior Notes in Q2 2017 and the purchase of Senior Notes as a result of the change of control, replaced with credit facility debt of $186.8 million and a $160.0 million Term Loan.  A weakening of the Canadian dollar in the first half of 2017 compared to the original guidance also impacted corporate costs.

Change of control costs impacting funds from operations of $0.70/boe include termination payments of $4.0 million and other preliminary costs of $0.4 million. Other costs that occurred in connection with the change of control were the settlement of the outstanding Awards for $14.9 million in the second quarter of 2017 and in the third quarter of 2017 financing costs of approximately $10.0 million and a premium paid on a USD call option of $2.1 million.

Guidance for annual funds from operations per boe (excluding the change of control costs) of $15.60/boe decreased from $17.65/boe largely due to lower oil prices and higher operating costs.

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.

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”, “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 six months ended June 30, 2017 and 2016.

The following table shows the calculation of field level free cash flow for Cactus Lake:

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;
• Methods and ability to finance operations, capital expenditure programs and working capital requirements;
• Estimated average drilling, completion and equipping costs for the Company’s 2017 drilling program;
• Percentage budgeted annual cash flow for 2017 required to maintain production at current levels;
• Anticipated oil and natural gas production levels in 2017;
• Continued enhancement of future production levels as a result of enhanced oil recovery initiatives at Cactus Lake;
• Production from long horizontal wells at 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;
• Base decline rates and corporate decline rates;
• 2017 payout ratio – normalized;
• 2017 funds from operations including and excluding change of control costs;
• The level of the Company’s annual cash financing costs following the Refinancing relative to its annual cash financing costs prior to the Refinancing;
• Plans for paying down the Term Loan through a combination of free cash flow and proceeds from the sale of non-core properties; and
• Redemption of the outstanding Senior Notes by the Company.

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.

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