TSX ticker symbol; BKX
QTCQX ticker symbol; BNKPF

CAMARILLO, California, March 20, 2018 /PRNewswire/ -- All amounts are in U.S. Dollars unless otherwise indicated:

2017 HIGHLIGHTS

• The Company's Total Proved Reserves increased by 40% to 25.2 million barrels of oil equivalent (BOE) and NPV10 value of the Total Proved Reserves increased by 73% to $259.5 million based on the Company's December 31, 2017 independent reserves evaluation.
• Funds from continuing operations was $6.5 million for 2017 compared to $4.9 million for 2016, an increase of 32%
• Average production for 2017 was 1,092 BOEPD, an increase of 4% compared to 2016 production of 1,045 BOEPD.  This increase was due to production from 3 new wells, the Chandler 8-6H well, the Hartgraves 1-6H well, and the Brock 9-2H well.  The production from these new wells was partially offset by the impact of three wells that were shut in during the first half of the year due to offset fracture stimulation by another operator in the Woodford formation beneath the Caney and normal production decline
• Subsequent to year end, the Company drilled the Glenn 16-2H well and has just finished fracture stimulation operations with production expected to start in April.  The Company has also drilled the WLC 14-2H well and expects fracture stimulation operations in mid-2018
• Percentage of oil produced increased to 74% in the fourth quarter of 2017 from 67% in the fourth quarter of 2016.   This is due to the new wells producing about 87% oil.
• Average netbacks were $25.49 per BOE in 2017, an increase of 52% compared to 2016 due to higher prices in 2017.  If the realized gains from the commodity contracts are included, the average netbacks for 2017 was $29.39 per BOE compared to $27.70 in 2016
• Revenue, net of royalties was $12.6 million for 2017 compared to $8.6 million in 2016 due to higher prices and production compared to 2016
• In June 2017, the Company's US subsidiary obtained a new $75 million credit facility from BOK Financial, with an initial commitment amount of $25.0 million.  In December 2017, the commitment amount was increased to $30.0 million.  As of December 31, 2017, the US subsidiary had borrowed $25.0 million of the commitment amount and had an available borrowing capacity of $5.0 million.
• Net loss was $1.6 million for 2017 compared to a net loss of $11.1 million in 2016.  The Company had an unrealized loss on financial commodity contracts of $1.2 million in 2017, compared to an unrealized loss of $8.0 million in 2016.
• General & administrative expenses decreased by 1% for 2017 compared to the prior year due to the Company's continued cost cutting efforts partially offset by advisor fees in 2017

BNK's President and Chief Executive Officer, Wolf Regener commented:

"We are very pleased with the results of our 2017 drilling program.  The three wells that came on production during the year have significantly increased our production.  Our average production for the fourth quarter of 2017 was 1,539 BOE per day, which was an increase of 132% from the fourth quarter of 2016.  Our 2017 drilling also significantly improved our reserve report, as our proved reserves increased by 40% from 2016, to 25.2 million BOE.  The NPV10 value of our proved reserves increased by 73% to $259.5 million compared to 2016.

"These results allowed us to obtain a $5 million increase in the borrowing capacity of our credit facility from $25 million to $30 million, which, along with our positive cash flow, is being used to fund our 2018 drilling program.   So far in 2018, we drilled and successfully completed the fracture stimulation of the Glenn 16-2H well which will begin flowback next week.  We expect production from this well to start in the beginning of April.  We have also drilled the WLC 14-2H well with fracture stimulation operations to follow in a few months.  All of these operations have been performed on time and under budget.  Total cost for the Glenn 16-2H well is expected to be less than the targeted $5.7 million budget.  Both of these wells had hydrocarbon shows comparable to some of our best wells and we expect both of these wells to further increase our reserves and cash flow.

"We generated funds from continuing operations of $2.8 million in the fourth quarter of 2017, which was a 455% increase from the fourth quarter 2016 amount of $0.5 million.  For all of 2017, funds from continuing operations totaled $6.5 million, which was an increase of 32% from 2016.

"Revenue, net of royalties was $5.0 million for the fourth quarter of 2017, an increase of 188% compared to the prior year fourth quarter amount of $1.7 million.  For 2017, revenue, net of royalties was $12.6 million compared to $8.6 million in 2016.

"Average netbacks for the fourth quarter of 2017 were $29.81 per BOE, an increase of 42% compared to the prior year fourth quarter due to higher prices and production.  For the year, average netbacks were $25.49 per BOE in 2017, an increase of 52% compared to 2016.  If we include the impact of the realized gains from the commodity hedging contracts, our average netbacks for 2017 were $29.39 per BOE, compared to $27.70 per BOE in 2016. 

"The Company recorded a net loss of $1.3 million in the fourth quarter of 2017, due to a $2.1 million unrealized loss on commodity contracts, compared to a net loss of $3.7 million in the fourth quarter of 2016.  For 2017, the Company had a net loss of $1.6 million, compared to a net loss of $11.1 million in 2016."                                                                                                       

Year Ended 2017 to Year Ended 2016

For 2017, oil and gas revenues net of royalties increased $4,013,000 or 47% to $12,591,000.  Oil revenues before royalties increased by 52% to $13,714,000 due to a 25% increase in prices between years and a 22% increase in production.  Natural gas revenues before royalties increased $17,000 or 2% due to a 31% increase in natural gas prices per mcf partially offset by a 22% decrease in average production.  NGL revenue before royalties increased $343,000 or 28% due to a 64% increase in average prices partially offset by a 22% decrease in production.

Exploration and evaluation expenses decreased $832,000.  The 2016 amount includes an impairment of $835,000 on exploration and evaluation leases.

Operating expenses increased by $263,000 due to an increase in production due to the new wells, an increase in production taxes and additional water hauling costs earlier in the year for the wells impacted by the offset fracture stimulation operations. 

Depletion and depreciation expense increased $247,000 due to increased production.

General and administrative expenses decreased $24,000 due to the Company's continued cost cutting efforts partially offset by advisor fees in 2017.

Finance income decreased $2,497,000 due to higher realized gains on risk management contracts in 2016 of $4,184,000, compared to $1,556,000 in 2017.  Finance expense decreased $7,072,000 due to a decrease in unrealized losses on risk management contracts of $6,843,000.

Capital expenditures of $19,271,000 were incurred in 2017 for drilling and completion costs in Oklahoma during the year.

FOURTH QUARTER HIGHLIGHTS:

• Funds from continuing operations was $2.8 million in the fourth quarter of 2017 compared to $0.5 million in the prior year fourth quarter, an increase of 455%, due to the increased production from the three additional wells drilled during 2017 and higher prices
• Revenue, net of royalties, was $5.0 million for fourth quarter 2017, an increase of 188% compared to the fourth quarter 2016 due to higher prices and increased production
• Average netbacks for the fourth quarter of 2017 were $29.81, an increase of 42% over fourth quarter 2016 due to price and production increases. If the realized gains from the commodity contracts are included, the average netbacks for the fourth quarter of 2017 are $30.46 per BOE compared to $31.40 per BOE for the fourth quarter of 2016
• Average production for the quarter was 1,539 BOEPD, an increase of 133% compared to the prior year fourth quarter mainly due to the increased production from the three additional wells drilled during 2017 and higher prices
• In December 2017, the commitment amount on the BOK credit facility was increased by $5 million to $30.0 million.  As of December 31, 2017, the US subsidiary had borrowed $25.0 million of the commitment amount and has an available borrowing capacity of $5.0 million.
• G&A expense increased by $153,000, or 18%, due primarily to advisor fees incurred in 2017
• A net loss of $1.3 million was incurred in the fourth quarter 2017 due to unrealized losses on commodity contracts of $2.1 million

Fourth Quarter 2017 to Fourth Quarter 2016

Oil and gas revenues net of royalties totaled $5,043,000 in the quarter versus $1,750,000 in the fourth quarter of 2016, an increase of 188%.  Oil revenues were $5,572,000 in the quarter versus $1,910,000 in the fourth quarter of 2016, an increase of 192% due to increased production of 156% and an increase in average oil prices of 14%.  Natural gas revenues increased 93% due to an increase in production of 90% in addition to an increase in natural gas prices of 1%.  NGL revenue increased 171% to $578,000 as average NGL production increased by 82% and by an average price increase of 49%.

Exploration and evaluation expenses decreased $832,000 in 2017 compared to 2016.  The 2016 amount includes an impairment of $835,000 on exploration and evaluation leases.

Operating expenses increased by $346,000 in the fourth quarter of 2017 compared to 2016 due to additional production and an increase in production taxes. 

Depletion and depreciation expense increased $1,025,000 due to increased production.

General and administrative expenses increased $153,000 between quarters due primarily to advisor fees in 2017.

The information outlined above is extracted from and should be read in conjunction with the Company's audited financial statements for the year ended December 31, 2017 and the related management's discussion and analysis thereof, copies of which are available under the Company's profile at www.sedar.com.

NON-GAAP MEASURES

Netback per barrel and netback including commodity contracts, net operating income and funds from operations (collectively, the "Company's Non-GAAP Measures") are not measures recognized under Canadian generally accepted accounting principles ("GAAP") and do not have any standardized meanings prescribed by GAAP. 

The Company's Non-GAAP Measures are described and reconciled to the GAAP measures in the management's discussion and analysis which are available under the Company's profile at www.sedar.com.

CAUTIONARY STATEMENTS

In this news release and the Company's other public disclosure:

Readers are referred to the full description of the results of the Company's December 31, 2017 independent reserves evaluation and other oil and gas information contained in its Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information for the year ended December 31, 2017, which the Company filed on SEDAR on March 14, 2018.

Caution Regarding Forward-Looking Information

This release contains forward-looking information including estimates of reserves, the proposed timing and expected results of exploratory and development work including production from the Company's Tishomingo field, Oklahoma acreage, the future performance of wells including following shut-in's and restart of well(s), the expected effects of cost reduction efforts, availability of funds from the Company's reserves based loan facility and the Company's strategy and objectives. The use of any of the words "target", "plans", "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. 

Such forward-looking information is based on management's expectations and assumptions, including that the Company's geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled, declines will match the modeling, future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management's expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that anticipated results and estimated costs will be consistent with managements' expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserves-based loan facility and that the borrowing base will not be reduced, that funds will be available from the Company's reserves based loan facility when required to fund planned operations, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company's business and its ability to advance its business strategy.

Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that the Company's geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with managements' expectations, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks including flooding and extended interruptions due to inclement or hazardous weather), the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company's assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserves-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base re-determination determination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funding is not available from the Company's reserves based loan facility at the times or in the amounts required for planned operations, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company's most recent Annual Information Form under the "Risk Factors" section, the Company's most recent management's discussion and analysis and the Company's other public disclosure, available under the Company's profile on SEDAR at www.sedar.com.

With respect to estimated reserves, the evaluation of the Company's reserves is based on a limited number of wells with limited production history and includes a number of assumptions relating to factors such as availability of capital to fund required infrastructure, commodity prices, production performance of the wells drilled, successful drilling of infill wells, the assumed effects of regulation by government agencies and future capital and operating costs. All of these estimates will vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material.  In addition to the foregoing, other significant factors or uncertainties that may affect either the Company's reserves or the future net revenue associated with such reserves include material changes to existing taxation or royalty rates and/or regulations, and changes to environmental laws and regulations. 

Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this release is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information.  The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.

About BNK Petroleum Inc.
BNK Petroleum Inc. is an international oil and gas exploration and production company focused on finding and exploiting large, predominately unconventional oil and gas resource plays. Through various affiliates and subsidiaries, the Company owns and operates shale gas properties and concessions in the United States. Additionally the Company is utilizing its technical and operational expertise to identify and acquire additional unconventional projects. The Company's shares are traded on the Toronto Stock Exchange under the stock symbol BKX.

For further information: Wolf E. Regener, President and Chief Executive Officer, +1 (805) 484-3613, Email: investorrelations@bnkpetroleum.com, Website: www.bnkpetroleum.com