Strategic Oil & Gas Ltd. Announces Second Quarter 2017 Financial Results and Provides Operations Update

CALGARY, ALBERTA--(Marketwired - Aug. 16, 2017) - Strategic Oil & Gas Ltd. ("Strategic" or the "Company") (TSX VENTURE:SOG in Strategic's interim unaudited consolidated financial statements and related Management's Discussion and Analysis ("MD&A") which will be available through the Company's website at www.sogoil.com and on SEDAR at www.sedar.com.

Highlights for the second quarter include:

• Completed and placed five new Muskeg horizontal wells on production, increasing average production volumes by 17% from the first quarter of 2017;
• Funds from operations increased 26% to $3.0 million from $2.4 million for the first quarter of 2017;
• Maintained a strong cash position with $29.0 million in adjusted working capital at June 30, 2017;
• Fracked Muskeg well 15-34 in the third quarter. Initial results are encouraging; the well will be tied in and placed on production in August 2017;
• Drilled two additional horizontal wells as a part of the summer drilling program. The two new wells are expected to be fracture stimulated in September.

FINANCIAL AND OPERATIONAL SUMMARY

		Three months ended June 30						Six months ended June 30
Financial ($thousands, except per share amounts)		2017		2016		% change		2017		2016		% change
Oil and natural gas sales		10,312		5,974		73		19,200		10,679		80
Funds from (used in) operations (1)		2,991		440		580		5,374		(1,740	)	-
	Per share basic (1) (3)	0.06		0.02		200		0.12		(0.06	)	-
Cash provided by (used in) operating activities		1,828		3,820		(52	)	1,879		2,345		(20	)
	Per share basic (3)	0.04		0.14		(71	)	0.04		0.09		(67	)
Net loss (2)		(7,020	)	(5,800	)	21		(11,460	)	(9,283	)	23
	Per share basic (3)	(0.15	)	(0.21	)	(29	)	(0.25	)	(0.34	)	(26	)
Net capital expenditures		12,784		1,152		1,010		30,851		9,449		227
Adjusted working capital (comparative figure is as of December 31, 2016) (1)		29,045		49,956
						(42	)	29,045		49,956		(42	)
Net debt (comparative figure is as of December 31, 2016) (1)		75,875		51,141		48		75,875		51,141		48
Operating
Average daily production
	Crude oil (bbl per day)	1,942		1,396		39		1,786		1,471		21
	Natural gas (mcf per day)	4,317		2,598		66		4,096		2,566		60
	Barrels of oil equivalent (boe per day)	2,661		1,829		46		2,468		1,899		30
Average prices
	Oil & NGL ($ per bbl)	51.69		44.27		17		52.68		36.89		43
	Natural gas ($ per mcf)	3.00		1.48		103		2.93		1.72		70
Operating netback ($ per boe) (1)
	Oil and natural gas sales	42.58		35.89		19		42.97		30.90		39
	Royalties	(4.61	)	(4.27	)	8		(5.03	)	(3.83	)	31
	Operating expenses	(19.05	)	(21.45	)	(11	)	(18.83	)	(21.96	)	(14	)
Transportation expenses		(0.94	)	(0.78	)	21		(1.17	)	(0.75	)	56
Operating Netback (1)		17.98		9.39		92		17.94		4.36		311
Common Shares (3)(thousands)
Common shares outstanding, end of period		46,388		27,116		71		46,388		27,116		71
Weighted average common shares (basic & diluted)		46,384		27,116		71		45,969		27,116		70

(1)	Funds from operations, adjusted working capital, net debt and operating netback are Non-GAAP measures; see "Non-GAAP measures" in the Company's MD&A.
(2)	The comparative condensed statement of loss for the six months ended June 30, 2016 has been adjusted to reflect a $3.8 million adjustment to deferred tax recovery related to the issuance of convertible debentures.
(3)	Adjusted for the share consolidation on a 20:1 basis announced on March 6, 2017.

QUARTERLY SUMMARY

• Capital expenditures of $12.7 million were incurred in the quarter, primarily on completion and related surface equipping costs for five horizontal Muskeg wells and drilling the 15-34 horizontal Muskeg well at north Marlowe.
  
  
• Average daily production increased 46% from the second quarter of 2016, and 17% from the first quarter of 2017 to 2,661 boe/d for the three months ended June 30, 2017, primarily due to new production from the winter Muskeg drilling program. Average daily production increased 30% from 1,899 boe/d for the six months ended June 30, 2016 to 2,468 boe/d the six months ended June 30,
  2017 due to production from the Company's fall 2016 and winter 2017 drilling programs coming online.
  
  
• Funds from operations increased significantly to $3.0 million and $5.4 million for the three and six months ended June 30, 2017 from funds from operations of $0.4 million for the second quarter of 2016 and funds used in operations of $1.7 million for the six months ended June 30, 2016, as higher commodity prices and production led to a $4.3 million increase in revenues for the quarter and $8.5 million increase in revenues for the six months ended June 30, 2017.
  
  
• New oil volumes coming online from the five-well drilling program contributed to lower operating costs on a per boe basis. Unit operating costs decreased to $19.05/boe and $18.83/boe for the three and six months ended June 30, 2017 from $21.45/boe and $21.96/boe for the comparable periods in 2016. These reductions were partially offset by higher transportation costs due to increased natural gas production and oil trucking charges caused by a temporary shutdown of the Rainbow pipeline. Unit general and administrative costs also decreased to $5.48/boe and $5.83/boe for the three and six months ended June 30, 2017 from $7.09/boe and $7.52/boe for the comparable periods in 2016 due to increased production.
  
  
• Strategic maintained capital discipline in the current uncertain oil pricing environment, as capital expenditures approximated guidance for the first half of 2017 despite some escalation in service costs during the period. At June 30, 2017, the Company had $29.7 million in cash and $29.0 million in adjusted working capital.
  
  
• Operating netbacks increased to $17.98/boe and $17.94/boe for the three and six months ended June 30, 2017 compared to $9.38/boe and $4.36/boe for the comparable periods in 2016 primarily due to higher commodity prices and production levels, combined with lower unit operating expenses.
  
  
• As a result of higher production levels, unit operating costs decreased 11% for the second quarter of
  2017 compared to the second quarter of 2016. General and administrative ("G&A") expenses per boe fell by 23% for the same time period.
  
  

PERFORMANCE OVERVIEW, STRATEGY AND OUTLOOK

During the second quarter, Strategic continued to execute its first half capital program which included drilling six horizontal Muskeg wells and the construction of a four kilometre pipeline to tie-in the 14-35 Muskeg well. The Company spent $30.9 million to drill six and complete five wells during the first half as compared to the budget of $30 million to drill and complete six wells. Five of the six wells drilled during the first quarter were fracture stimulated and tied-in midway through the second quarter and the sixth well was completed in the third quarter.

Like many operators in western Canada, Strategic was unable to secure frac services in the first quarter of 2017 resulting in significant delays in adding new production volumes during the first half of 2017. Even with the production growth limited to the latter part of the second quarter, the Company did achieve a 17% increase in production from the first quarter.

With five of the six wells fracked and tied in production peaked over 4,000 boe/d in the second quarter. Simultaneous flow-back of five new wells increased pipeline pressure, which curtailed the peak rates from the new Muskeg wells and also backed out some existing base production. Further, due to maintenance and upgrades on Alberta's main natural gas sales pipeline, Strategic had to shut in 600 boe/d of production by shutting in certain oil and gas wells for nearly two weeks in June.

Initial production rates for eight recent Muskeg wells are as follows:

			IP30			IP60
Well	Date	BOPD	BOEPD	% Oil	BOPD	BOEPD	% Oil
2-13	Q4-16	397	712	56%	294	529	56%
14-12	Q4-16	294	340	86%	247	309	80%
14-35	Q1-17	379	794	48%	275	614	45%
5-12	Q2-17	118	127	93%	120	130	92%
11-12	Q2-17	133	143	93%	152	177	86%
13-01	Q2-17	221	257	86%	190	250	76%
02/13-01	Q2-17	198	238	83%	177	234	76%
16-35	Q2-17	241	248	97%	221	268	82%
Average		248	357	69%	210	314	67%

	(1)	Includes producing days only.
	(2)	Five Muskeg wells were brought on production during May due to delays in obtaining frac services during the first quarter of 2017. The initial peak production of the five wells 5-12, 11-12, 13-01, 02/13-01 and 16-35 was somewhat affected by pipeline pressures which spiked up during May and June due to simultaneous flow-back of five new wells.

A graph of the average production from the wells drilled in 2016 (on-stream in the fourth quarter of 2016 and the first quarter of 2017) and the wells drilled in 2017 and brought on-stream in the second quarter is as follows:

http://www.marketwire.com/library/20170816-1100964-Graph-gr.png

Strategic's capital expenditure plan for 2017 had contemplated bringing two new wells on-stream per month from March to May 2017 in order to manage pipeline pressures and maximize average production volumes for the second quarter. Due to delays in completions all five new wells were brought online in May 2017 and the flow back of the five new wells resulted in an increase in line pressures which had an adverse impact on initial production volumes from all wells on the west Marlowe pipeline. The Company intends to use higher capacity pumps on future wells. In addition, Strategic installed temporary field compression on one of its pads at west Marlowe and the system installed was effective at reducing casing pressures and significantly increasing oil and gas production from the related well to volumes consistent with the 2016 wells. These efforts, while causing additional well downtime and higher operating costs in this quarter, should enhance productivity on future drilling programs.

The Company is actively developing its asset base in the third quarter and has recently executed a 40 stage completion on the Muskeg well drilled during the second quarter. This well is located in north Marlowe where pipeline pressures are lower compared to west Marlowe. Initial results are encouraging; the well will be tied in and placed on production in August 2017. The Company drilled two other horizontal wells in July, which will also be completed and tied in during the third quarter of 2017.

Corporate production at the end of the second quarter was approximately 3,000 boe/d. The Company has experienced ongoing production curtailments totaling 17 days in July and August. Strategic has been notified of additional third party restrictions due to pipeline maintenance of up to 15 days in September. As a result of these restrictions and a scheduled 8-day plant turnaround, corporate production volumes for the third quarter of 2017 are estimated to be 2,400 boe/d. Production is expected to be 3,500 boe/d once the curtailments have been lifted and all wells are brought back online. Given the external limitations on corporate sales volumes, Strategic elected to defer the last two wells in its summer drilling program and reduced estimated capital spending for the third quarter from $24 million to $16 million.

About Strategic

Strategic is a junior oil and gas company committed to becoming a premier northern oil and gas operator by exploiting its light oil assets primarily in northern Alberta. The Company relies on its extensive subsurface and reservoir experience to develop its asset base and grow production and cash flows while managing risk. The Company maintains control over its resource base through high working interest ownership in wells, construction and operation of its own processing facilities and a significant undeveloped land and opportunity base. Strategic's primary operating area is at Marlowe, Alberta. Strategic's common shares trade on the TSX Venture Exchange under the symbol SOG.

ADDITIONAL INFORMATION

Additional information is also available at www.sogoil.com and at www.sedar.com.

Reader Advisories

Any references in this news release to initial production or test rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily determinative of the rates at which such wells will continue production. These flow-back, initial production or test results are quoted on a raw basis before shrinkage on natural gas volumes and may not be indicative of long-term well performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in estimating the aggregate production for the Company. Total corporate production volumes include natural gas shrinkage.

Forward-Looking Statements

This news release includes certain information, with management's assessment of Strategic's future plans and operations, and contains forward-looking statements which may include some or all of the following: (i) anticipated production rates and productivity of future drilling programs; (ii) expected operating costs and the impact of production levels on unit operating and G&A costs; (iii) expected capital spending and wells to be drilled; (iv) the Company's financial strength and capitalization; (v) estimates of timing for pipeline maintenance and turnarounds and their effect on production; which are provided to allow investors to better understand the Company's business. By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond Strategic's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources, and other risks and uncertainties described under the heading 'Risk Factors' and elsewhere in the Company's Annual Information

Form for the year ended December 31, 2016 and other documents filed with Canadian provincial securities authorities, available to the public at www.sedar.com. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward -looking statements. The principal assumptions Strategic has made includes security of land interests; drilling cost stability; royalty rate stability; oil and gas prices to remain in their current range; finance and debt markets continuing to be receptive to financing the Company and industry standard rates of geologic and operational success. Actual results could differ materially from those expressed in, or implied by, these forward-looking statements. Strategic disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Basis of Presentation

This discussion and analysis of Strategic's oil and natural gas production and related performance measures is presented on a working-interest, before royalties basis. For the purpose of calculating unit information, the Company's production and reserves are reported in barrels of oil equivalent (boe) and boe per day (boed). Boe may be misleading, particularly if used in isolation. A boe conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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.

Non-GAAP Measurements

The Company utilizes certain measurements that do not have a standardized meaning or definition as prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other entities, including net debt, operating netback and funds from operations. Readers are referred to advisories and further discussion on non-GAAP measurements contained in the Company's MD&A.

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 release.