CAMARILLO, CA, Aug. 10, 2017 /CNW/ -
All amounts are in U.S. Dollars unless otherwise indicated:
SECOND QUARTER HIGHLIGHTS:
BNK's President and Chief Executive Officer, Wolf Regener commented:
"We are excited to be about 75% complete with the Hartgraves 1-6H (100% working interest) fracture stimulation operations that were announced last week. We expect to be finished within the next week and plan to start flowback of the well immediately thereafter. The Hartgraves 1-6H completion operations have been proceeding as originally designed, which entails increased amounts of proppant and shorter stage spacings. The Hartgraves 1-6H well is the second well to be fracture stimulated under our 2017 drilling program, as we finished drilling and completing the Chandler 8-6H well (99.9% working interest) in the first quarter. We intend to commence completion operations on the previously drilled Brock 9-2H (100% working interest), the third well in our 2017 drilling program, within weeks after the Hartgraves 1-6H well is completed. We are looking forward to the completion of these next two wells which will incorporate our previous learnings including refined placement of the laterals as well as improved completion designs.
During the second quarter, we also obtained a new $75 million credit facility with BOK Financial with a June 2022 maturity date. The Company borrowed $21 million of our initial borrowing commitment of $25 million and used it primarily to payoff our existing credit facility which was maturing in July 2018. In addition, the lower interest rate on the new credit facility will reduce our interest payments by over $650,000 a year. We look forward to working with BOK Financial in the future as we grow and develop the Tishomingo field.
Our net revenue increased by 1% in the second quarter 2017 as the average price increase of 20% offset the 16% decrease in average production as compared to the prior year quarter. Production during the second quarter of 2017 decreased as compared to the second quarter of 2016 primarily due to three wells that were shut-in for all of the first quarter and part of the second quarter of 2017, caused by offset fracture stimulation operations on 19 wells by another operator in the Woodford formation beneath the Caney and also due to the normal production decline. This was partially offset by the production from the Chandler 8-6H well that started producing in March 2017. During the second quarter, the three shut-in wells were still pumping off the offset operator's frack water with production levels improving slowly, but still less than their pre-shut in levels. The shut-in wells decreased second quarter 2017 average production by about 200 BOEPD and year to date 2017 average production by 220 BOEPD. The Company expects the wells to require a few more months to pump off the rest of the offset fracture stimulation fluids in order to fully recover. The Company does not expect any impact on the long-term production of the wells, even though the wells have recovered slower than expected.
The increase in average prices and the addition of the production of Chandler 8-6H well in the second quarter allowed the Company to generate operating cash flow from continuing operations of $1.4 million for the second quarter of 2017, which was an increase of more than $1.1 million from the first quarter of 2017.
The Company's hedging position has continued to allow us to realize higher prices than current market levels for a portion of our production. During the second quarter 2017, the Company was able to realize an average price of $64.00 on more than 65% of its oil production. We expect a comparable level of hedging in the rest of 2017 as the Company has commodity contracts in place to recognize an average price of about $59.00/bbl on almost 70% of existing 2017 production going forward, excluding the new production expected to come on-line from the Hartgraves 1-6H and Brock 9-2H wells.
Average netbacks for the second quarter 2017 were $21.30, an increase of 19% compared to the prior year second quarter due to the 20% average price increase. If we include the impact of the realized gains from the commodity contracts, our average netbacks for the second quarter would be $27.99, which is an increase of 3% compared to the 2016 second quarter.
"In the second quarter of 2017, the Company generated a net income of $56,000 compared to net loss of $5.3 million in the second quarter of 2016. The 2016 net loss included unrealized losses on commodity contracts of $4.7 million compared to unrealized gains on commodity contracts of $0.6 million in the second quarter of 2017."
| Second Quarter |
First Six Months |
|||||
| 2017 |
2016 |
% |
2017 |
2016 |
% |
|
| Net Income (Loss): |
||||||
| $ Thousands |
$56 |
$(5,310) |
- |
$1,040 |
$(6,560) |
- |
| $ per common share |
$0.00 |
$(0.03) |
- |
$0.00 |
$(0.04) |
- |
| assuming dilution |
||||||
| Capital Expenditures |
$940 |
$406 |
132% |
$11,484 |
$537 |
2,039% |
| Average Production (Boepd) |
970 |
1,149 |
(16%) |
862 |
1,250 |
(31%) |
| Average Price per Barrel |
$36.16 |
$30.19 |
20% |
$38.46 |
$25.61 |
50% |
| Average Netback per Barrel |
$21.30 |
$17.90 |
19% |
$23.26 |
$14.88 |
56% |
| Average Price per Barrel including |
$42.85 |
$39.45 |
9% |
$45.34 |
$37.22 |
22% |
| Average Netback per Barrel including |
$27.99 |
$27.16 |
3% |
$30.14 |
$26.49 |
14% |
| June |
March |
December |
||||
| Cash and Cash Equivalents |
$830 |
$6,988 |
$11,101 |
|||
| Working Capital |
$1,478 |
$1,108 |
$10,640 |
|||
Second Quarter 2017 versus Second Quarter 2016
Oil and gas gross revenues totaled $3,191,000 in the second quarter 2017 versus $3,157,000 in the second quarter of 2016. Oil revenues were $2,678,000 in the quarter versus $2,592,000 in the second quarter of 2016, an increase of 3% as average oil prices increased 9% or $3.70 a barrel for the quarter while production decreased by 5%. Natural gas revenues increased $1,000 or 1%, as a 50% increase in average natural gas prices compared to the second quarter of 2016 offset natural gas production decreases of 33%. Natural Gas Liquid (NGL) revenue decreased $52,000 or 13% to $342,000 as average production decreased 29% offset by an average NGL price increase of 22%.
Production and operating expenses increased $23,000 between quarters. Operating expenses averaged $6.73 per BOE for the second quarter of 2017 compared to $5.46 per BOE for the same period in 2016. The per BOE operating expense increase for 2017 is due to the additional water hauling and disposal costs once the shut-in wells were returned to production as well as a decrease in production from the shut-in wells. If these water hauling and disposal costs are excluded from the total, the operating expenses for the second quarter of 2017 would be reduced to $5.82 per BOE. As the production from the new wells comes on and the water hauling/disposal costs return to normal we expect our operating expenses to return to the mid-to-low $5 per BOE range.
Depletion and depreciation expense decreased $186,000 between quarters due to decreased production.
General and administrative expenses increased $64,000 between quarters due to a one-time charge, increasing legal and professional fees.
Finance income increased $244,000 due to unrealized gains on financial commodity contracts in 2017. Finance expense decreased $4,595,000 due to 2016 unrealized loss on financial commodity contracts of $4,728,000.
FIRST SIX MONTHS 2017 HIGHLIGHTS
First Six Months of 2017 versus First Six Months of 2016
Gross oil and gas revenues totaled $6,000,000 in the first six months of 2017 versus $5,825,000 in the first six months of 2016. Oil revenues were $5,079,000 in the first six months versus $4,639,000 in the same period of 2016, an increase of 9% as average oil prices increased 32% or $11.39 a barrel offset by a decrease in oil production of 16%. Natural gas revenues decreased $141,000 or 30%, due to an average natural gas production decrease of 53% in the first six months of 2017 offset by an increase in natural gas prices of 51%. NGL revenue decreased $124,000, or 17%, due to a decrease in NGL production of 48%, partially offset by an average NGL price increase of 59% in the first six months of 2017.
Production and operating expenses decreased 9% for the first six months of 2017 due to a decrease in production. Operating expenses averaged $6.54 per BOE for the first six months of 2017 compared to $4.94 per BOE for the same period in 2016. The per BOE operating expense increase for 2017 are due to the decrease in production from the shut-in wells as well as additional water hauling and disposal costs once the shut-in wells were returned to production. If these water hauling and disposal costs are excluded from the total, the operating expenses for the first six months of 2017 would be reduced to $5.77 per BOE.
Depletion and depreciation expense decreased $900,000 due to decreased production.
General and administrative expenses decreased $97,000 primarily due to management's efforts to reduce staffing, benefit and travel costs throughout the Company which were partially offset by a one-time charge that increased legal and professional fees.
Finance income increased $604,000 due to an unrealized gain on financial commodity contracts in 2017 of $2.2 million offset by lower realized gains in 2017. Finance expense decreased $5,449,000 due to a 2016 unrealized loss on financial commodity contracts of $5,520,000.
| BNK PETROLEUM INC. |
|||||||||
| CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) |
|||||||||
| (Unaudited, expressed in Thousands of United States dollars, except per share amounts) |
|||||||||
| Second Quarter |
First Six Months |
||||||||
| 2017 |
2016 |
2017 |
2016 |
||||||
| Oil and natural gas revenue, net |
$ |
2,473 |
2,443 |
4,650 |
4,507 |
||||
| Other income |
75 |
- |
76 |
1 |
|||||
| 2,548 |
2,443 |
4,726 |
4,508 |
||||||
| Exploration and evaluation expenditures |
- |
- |
- |
- |
|||||
| Production and operating expenses |
594 |
571 |
1,021 |
1,123 |
|||||
| Depletion and depreciation expense |
1,238 |
1,424 |
2,195 |
3,095 |
|||||
| General and administrative expenses |
996 |
932 |
1,933 |
2,030 |
|||||
| Stock based compensation |
43 |
323 |
87 |
362 |
|||||
| 2,871 |
3,250 |
5,236 |
6,610 |
||||||
| Finance income |
1,212 |
968 |
3,249 |
2,645 |
|||||
| Finance expense |
(638) |
(5,233) |
(1,107) |
(6,556) |
|||||
| Net income (loss) and comprehensive |
$ |
251 |
(5,072) |
1,632 |
(6,013) |
||||
| Net loss and comprehensive loss from |
(195) |
(238) |
(592) |
(547) |
|||||
| Net income (loss) |
56 |
(5,310) |
1,040 |
(6,560) |
|||||
| Net income (loss) per share |
$ |
0.00 |
(0.03) |
0.00 |
(0.04) |
||||
| BNK PETROLEUM INC. |
||||||
| SECOND QUARTER 2017 |
||||||
| ($000 except as noted) |
||||||
| Second Quarter |
First Six Months |
|||||
| 2017 |
2016 |
2017 |
2016 |
|||
| Oil revenue before royalties |
$ |
2,678 |
2,592 |
5,079 |
4,639 |
|
| Gas revenue before royalties |
172 |
171 |
329 |
470 |
||
| NGL revenue before royalties |
342 |
394 |
593 |
717 |
||
| Oil and Gas revenue |
3,192 |
3,157 |
6,001 |
5,826 |
||
| Cash flow from continuing operations |
1,395 |
1,716 |
1,674 |
3,543 |
||
| Additions to property, plant & equipment |
(940) |
(406) |
(11,484) |
(537) |
||
| Statistics: |
||||||
| 2nd Quarter |
First Six Months |
|||||
| 2017 |
2016 |
2017 |
2016 |
|||
| Average Oil production (Bopd) |
638 |
672 |
592 |
708 |
||
| Average natural gas production (mcf/d) |
793 |
1,181 |
673 |
1,441 |
||
| Average NGL production (Boepd) |
200 |
280 |
158 |
302 |
||
| Average production (Boepd) |
970 |
1,149 |
862 |
1,250 |
||
| Average oil price ($/bbl) |
$46.11 |
$42.41 |
$47.41 |
$36.02 |
||
| Average natural gas price ($/mcf) |
$2.38 |
$1.59 |
$2.70 |
$1.79 |
||
| Average NGL price ($/bbl) |
$18.80 |
$15.45 |
$20.72 |
$13.04 |
||
| Average price per barrel |
$36.16 |
$30.19 |
$38.46 |
$25.61 |
||
| Royalties per barrel |
8.13 |
6.83 |
8.66 |
5.79 |
||
| Operating expenses per barrel |
6.73 |
5.46 |
6.54 |
4.94 |
||
| Netback per barrel |
$21.30 |
$17.90 |
$23.26 |
$14.88 |
||
| Average price per barrel including |
$42.85 |
$39.45 |
$45.34 |
$37.22 |
||
| Royalties per barrel |
8.13 |
6.83 |
8.66 |
5.79 |
||
| Operating expenses per barrel |
6.73 |
5.46 |
6.54 |
4.94 |
||
| Netback per barrel including |
$27.99 |
$27.16 |
$30.14 |
$26.49 |
||
The information outlined above is extracted from and should be read in conjunction with the Company's unaudited financial statements for the three months ended June 30, 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 netbacks 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 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:
| (a) |
The Company's natural gas production is reported in thousands of cubic feet ("Mcfs"). The Company also uses references to barrels ("Bbls") and barrels of oil equivalent ("Boes") to reflect natural gas liquids and oil production and sales. Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. |
| (b) |
Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value. |
| (c) |
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. |
| (d) |
The Company discloses short-term production rates. Readers are cautioned that such production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery. |
Caution Regarding Forward-Looking Information
This release contains forward-looking information including information regarding the Company's commodity contract hedges, anticipated results from the Company's cost reduction measures, 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 following shut-in and restart, availability of funds from the Company's reserves based loan facility, the effect of design and performance improvements on future productivity, planned capital expenditure programs and cost estimates, planned use and sufficiency of cash on hand and cash flow from operations 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 will achieve a comparable level of hedging going forward in respect of its existing production, that the Company will achieve the results anticipated by management from its cost reduction measures, that the Company's geologic models 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 anticipated results and estimated costs will not be consistent with managements' expectations, that the Company will not achieve a comparable level of hedging going forward in respect of its existing production, that the Company's geologic and reservoir models or analysis are not validated, that the Company will not achieve the results anticipated by management from the Company's cost reduction measures, 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 conditions), 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 and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funds will not be available from the Company's reserves based loan facility when required to fund 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.
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.
SOURCE BNK Petroleum Inc.
Wolf E. Regener, President and Chief Executive Officer, +1 (805) 484-3613, Email: [email protected], Website: www.bnkpetroleum.com
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