Virginia Hills Oil Corp. Announces Third Quarter of 2016 Results and General Operation Update

CALGARY, ALBERTA--(Marketwired - Nov. 30, 2016) -

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES OF AMERICA.

Virginia Hills Oil Corp. (TSX VENTURE:VHO) ("Virginia Hills" or the "Company") announces its operating and financial results as at and for the three and nine months ended September 30, 2016, and provides a general corporate operational. The Company's unaudited interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2016 are available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com or on the Company's website at www.virginiahillsoil.com.

OPERATIONAL UPDATE

Oil and natural gas prices have continued to be volatile over the first nine months of 2016. Benchmark crude oil monthly average WTI prices ranged from a low of USD $30.62/bbl in February 2016 to a high of USD $49.94/bbl in October. Benchmark WTI pricing in the third quarter of 2016 slipped lower by approximately 1% from the average achieved in the second quarter of 2016 to average USD $44.94/bbl. Historically, Virginia Hills' realized commodity prices have tracked the Canadian benchmark oil price due to its corporate production and revenue weighting derived from light oil and natural gas liquids of 97% of and 99%, respectively. The Company's Q3 2016 realized corporate average prices decreased approximately 16% to $51.54 per boe compared to $61.38 per boe in Q2 2015 due to lower pricing. The Company expects its future corporate pricing to track the WTI benchmark pricing as it has not hedged any of its future production.

During the third quarter, the Company drilled its third long-leg horizontal well in its core Red Earth operating area at Loon 102/16-27-086-09W5 ("02/16-27") and achieved the fastest drilling time, based on public record, to the Slave Point Formation with measured depths ranging from 2,500 meters to 3,000 meters. The well's 30-day initial production rate was 100 bbl/d of light oil, which is in line with the Company's previously disclosed acid frac type curve for the Red Earth area. The 02/16-27 well was drilled within one of the Company's water flood project areas approximately 200 meters away from an existing water injection well. At year end 2015, the Company had twelve long leg horizontals producing within in its existing water flood projects spaced a distance of 200 meters from off-setting water injection, on average these twelve wells had approximately 200 mbbl of recoverable light oil reserves assigned to them on a proved plus probable basis. The 02/16-27 well is performing in line with historical analogs. The Company maintains a significant water flood project area in the greater Red Earth area and currently has 4.5 net sections under water flood out of a total development area of 22.0 net sections.

During the third quarter, the Company expensed approximately $0.6 million or $4.90 per boe on production and cost optimization projects. Specifically the Company completed sand clean outs and pump optimization projects on four (3.6 net) wells and installed field compression to reduce flaring at one field water injection facility. Net incremental production on a quarter over quarter basis associated with these projects was 50 boe/d (90% light oil and NGLs). The Company will continue to monitor the aggregate performance of these projects and, if warranted, all or a portion of these expenditures may be re-classified to capital from operating costs at year end if both incremental reserves are added and they are deemed non-occurring in nature.

As announced its press release on August 26, 2016, Virginia Hills initiated a process to review strategic alternatives with a view of maximizing the value of the Company's significant Slave Point light oil resource base. The Company does not have any further update at this time as it continues to evaluate different alternatives in light of its current financial position. Any strategy, if taken, is subject to material uncertainty and could have a material impact on the Company's financial position and results of operations. Virginia Hills does not intend to disclose developments with respect to this process unless and until the board of directors of the Company has approved a definitive transaction or other course of action or otherwise deems that disclosure of developments is appropriate or otherwise required by law. There are no guarantees that the process will result in a transaction of any form or, if a transaction is entered into, as to its terms or timing.

THIRD QUARTER FINANCIALS

		Three months ended September 30		Nine months ended September 30
(Canadian $000, except per unit amounts)		2016	2015	2016	2015
FINANCIAL
Petroleum and natural gas sales		$ 6,289	$ 8,302	$ 17,149	$ 23,738
Funds flow from (used in) operations (2)		(366)	1,079	(1,398)	3,502
	Per share - basic	(0.02)	0.05	(0.07)	0.29
	Per share - diluted	(0.02)	0.05	(0.07)	0.29
Net income (loss)		(30,580)	(3,098)	(38,160)	340
	Per share - basic	(1.46)	(0.16)	(1.87)	0.03
	Per share - diluted	(1.46)	(0.16)	(1.87)	0.03
Capital expenditures (3)		1,830	7,246	1,991	10,093
Net debt (2)(4)		112,660	110,949	112,660	110,949
Common Shares Outstanding (1)
	Weighted average - basic	20,954	19,724	20,354	12,050
	Weighted average - diluted	20,954	19,724	20,354	12,050
OPERATIONAL
Number of days		92	92	274	273
Production
	Oil and NGL (bbl/d)	1,285	1,416	1,307	1,482
	Natural gas (mcf/d)	250	325	244	304
	Total production (boe/d)	1,326	1,470	1,347	1,533
Average realized prices (5)
	Oil and NGL ($/bbl)	53.04	63.44	47.60	58.49
	Natural gas ($/mcf)	0.90	1.18	0.87	0.89
Netback per boe ($) (2)
	Petroleum and natural gas sales	51.54	61.36	46.45	56.73
	Royalties	(6.37)	(6.53)	(4.21)	(5.14)
	Production and transportation expenses	(31.36)	(29.85)	(31.00)	(26.86)
	Field netback (2)	13.81	24.98	11.24	24.73
Drilling
	Gross wells	1.0	2.0	1.0	2.0
	Net wells	1.0	2.0	1.0	2.0

(1) Shares and per share amounts for comparative periods reflect the 100:1 share consolidation that occurred April 15, 2015 concurrent with the capital reorganization as though the consolidation took place at the beginning of the earliest period.

(2) Non-GAAP measure. See Reader Advisory for further information on such terms.

(3) Capital expenditures exclude amounts paid for acquisitions.

(4) Net debt is defined as current assets minus current liabilities, plus outstanding bank debt.

(5) Before the effects of derivative financial instruments, but includes gains or losses on fixed price, physical contracts that are not considered derivative instruments.

GUIDANCE FOR 2016

At the end of the third quarter and into the beginning of the fourth quarter of 2016, the oil and gas industry was affected by extremely wet surface conditions in Alberta which resulted in limited surface access in certain areas. At current commodity prices the Company did not deem it feasible to initiate any additional field activities until frozen ground conditions were present later in the fourth quarter. These conditions will result in the deferral of certain of the Company's water flood related projects to the first quarter of 2017 from the fourth quarter of 2016.

As a result, the Company is anticipating its 2016 exit volumes to range from 1,325 boe/d (97% light oil and NGLs) to 1,400 boe/d (97% light oil and NGLs), with an additional 100 bbl/d of light oil water flood production previously scheduled to be online in the fourth quarter of 2016 to be brought on line during the first quarter of 2017.

READER ADVISORY

FORWARD-LOOKING STATEMENTS: This news release contains forward-looking statements. More particularly, this news release contains statements concerning Virginia Hills' expectations regarding improvement to the Company's cost structure, the implementation and timing of effect of optimization projects and the timing thereof; future corporate pricing in relation to WTI; future production rates and performance of the 02/16-27 well; the re-classification of production and cost optimization expenditures; the results of the Company's strategic alternatives process; the initiation of future field activities; 2016 exit volumes and oil and natural gas weightings; timing for bringing water flood production online; and future oil prices. In addition, the use of any of the words "guidance", "initial, "scheduled", "can", "will", "prior to", "estimate", "anticipate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements.

The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, including the water flood projects discussed herein, the availability of capital, estimated volume and product mix of the Company's oil and gas production, forecasted exit 2016 production, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of existing wells, the performance of new wells, estimated future drilling inventory, general economic conditions, availability of required equipment and services, prevailing commodity prices and completion of the Company's strategic review process, including time and disclosure of developments related thereto and potential transaction the Company may pursue as a result of the process. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties.

Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (including, operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; as the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures.

The forward-looking statements contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

NON-GAAP MEASURES: This news release contains the terms "funds flow from (used in) operations", "net debt", "field netback" and "operating netback" which do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These measures should not be construed as an alternative to other terms that are calculated in accordance with IFRS. Management uses funds flow from (used in) operations to analyze operating performance and leverage. Management believes "net debt" is a useful supplemental measure of the total amount of current and long-term debt of the Company and to understand liquidity at specific points in time. Mark-to-market risk management contracts are excluded from the net debt calculation. Management calculates "field netback" and "operating netback" as the amount of revenues received after royalties and production and transportation costs, and the amount of revenues received after royalties, production, transportation costs and realized gain (loss) on derivatives. Management believes these measures are useful to understand profitability relative to current commodity prices and a benchmark of operational performance against prior periods and peers. Additional information relating to certain of these non-GAAP measures, including the reconciliation between funds flow from operations and cash flow from operating activities can be found in the MD&A.

BOE ADVISORY: To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

INITIAL PRODUCTION RATES: Any references in this press release to initial production rates or flow back production results are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.

ANALOGOUS INFORMATION: Certain noted production information provided in this press release may constitute "analogous information" under applicable securities legislation, such as production rates from wells drilled by the Company or other industry participants located in geographical proximity to the 02/16-27 well. This information is compiled by management or by independent sources, as the case may be, and readers are cautioned that the information may contain errors, may not be analogous to the 02/16/-27 well and/or may not be representative of actual results of wells anticipated of the 02/16-27 well in the future.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this press release.