Lightstream Announces Second Quarter Production of 46,045 boepd and Funds Flow from Operations of $168 Million

CALGARY, ALBERTA--(Marketwired - Aug. 7, 2013) - Lightstream Resources Ltd. (the "Company" or "Lightstream") (TSX:LTS) is pleased to announce our second quarter financial and operating results and to update our 2013 guidance.

SECOND QUARTER FINANCIAL & OPERATING HIGHLIGHTS

• Second quarter production averaged 46,045 barrels of oil equivalent per day ("boepd") (82% light oil and liquids), a decrease of 6% from the first quarter of 2013 and an increase of 19% over the second quarter 2012.
• Production for the first half of 2013 averaged 47,553 boepd, an 11% increase over the first half of 2012.
• Our operating netback for the second quarter was $50.08/boe, a slight increase over the first quarter of 2013. During the second quarter WTI averaged US$94.22/bbl.
• Funds flow from operations was $168 million ($0.86 per basic share) for the quarter, representing a 5% decrease from the first quarter of 2013 and an increase of 39% over the second quarter of 2012.
• Capital expenditures before acquisitions and dispositions totalled $117 million in the second quarter, resulting in 7 wells drilled, 20 wells placed on production and 14 wells in inventory at the end of the quarter.

Summary of Results
		Three months ended June 30, ($000s)			Six months ended June 30, ($000s)
		2013		2012	2013		2012
Oil and natural gas sales		315,417		240,205	630,950		570,566
Funds flow from operations (1)		168,212		121,390	345,198		306,717
	Per share - basic ($)(1)(2)	0.86		0.65	1.78		1.64
Adjusted Net income (loss) (1)		(50,597	)	25,709	(49,041	)	128,318
	Per share - basic ($)(1) (2)	(0.26	)	0.14	(0.25	)	0.68
Net Capital Expenditures(1)		116,982		98,443	425,402		(311,643	)
Total debt (1)		2,232,656		1,661,167	2,232,656		1,661,167
Dividends per share ($)(2) (3)		0.24		0.24	0.48		0.48
Cash dividends per share ($)(2) (3)		0.18		0.09	0.34		0.23
Common Shares, end of period (000) (4)		196,136		187,897	196,136		187,897
Operating netback ($/boe) (1) (5) (6)		50.08		45.08	49.93		49.32
Average daily production (boe) (5)		46,045		38,715	47,553		42,719

(1)	Non-GAAP measure. See "Non-GAAP Measures" section.
(2)	2012 balance calculated using shares outstanding of Lightstream prior to the reorganization with Petrobank Energy and Resources Ltd. in December 2012.
(3)	2012 balance represents dividends paid by Lightstream prior to the reorganization in December 2012.
(4)	Denotes basic common shares outstanding.
(5)	Six Mcf (thousand cubic feet) of natural gas is equivalent to one barrel of oil equivalent ("boe").
(6)	Net of transportation expenses.

OPERATING RESULTS

Our second quarter average production of 46,045 boepd was comprised of 20,180 boepd from the Cardium business unit and 16,564 boepd from the Bakken business unit, with the remainder from the Saskatchewan Conventional and AB/BC business units. Production for the second quarter was ahead of our forecast due to our maturing production base, infrastructure investments and a shorter spring break-up. Our production was up 19% compared to the second quarter of 2012, reflecting the successful execution of our 2012 and 2013 capital plan.

Average Daily Production
		Three months ended June 30, 2013			Six months ended June 30, 2013
Business Unit		Oil &NGL (bbl/d)	Gas (Mcf/d)	Total (boe/d)	Oil &NGL (bbl/d)	Gas (Mcf/d)	Total (boe/d)
	Bakken	15,645	5,517	16,564	16,865	5,537	17,788
	Conventional (SE SK)	5,434	1,318	5,654	5,632	1,386	5,863
	Cardium (central AB)	14,583	33,585	20,180	14,722	34,047	20,396
	Alberta/BC	1,920	10,363	3,647	1,759	10,482	3,506
		37,582	50,783	46,045	38,978	51,452	47,553

While production during the second quarter was marginally impacted by spring break up, we did experience our normal seasonal slowdown in field activities because of road bans and field conditions. During the quarter, we drilled 7 wells and brought 20 wells on-production, with an additional 14 wells waiting in inventory to be completed and/or brought on production.

Q2 2013 Drilling Activity
		Drilled		Completed		On Production		Inventory(1)
Business Unit		Gross	Net	Gross	Net	Gross	Net	Gross	Net
	Bakken	4	3	3	1	3	1	6	4
	Conventional (SE SK)	3	-	2	1	3	1	3	1
	Cardium (central AB)	4	2	17	13	21	17	7	5
	Alberta/BC	2	2	4	4	1	1	5	4
Total		13	7	26	19	28	20	21	14

(1)	Inventory refers to the number of wells pending completion and/or tie-in at June 30, 2013.

Bakken Business Unit

Production in the Bakken business unit averaged 16,564 during the second quarter, down 13% from the first quarter and up 12% over the second quarter of 2012. Field activity resumed late in June, and we are expanding our field optimization program due to the success of these investments in the first half of the year. Our enhanced oil recovery (EOR) plans continue to advance, and we are on track to expand our natural gas injection projects in 2014. A maturing production base, combined with a significant inventory of drilling locations and well optimization candidates, allows us to continue to generate significant free cash flow from this business unit.

Saskatchewan Conventional Business Unit

Our southeast Saskatchewan Conventional business unit also continues to generate free cash flow from our low decline, light oil production base. Similar to the Bakken business unit profile, production of 5,654 boepd decreased 7% from the first quarter but was up 10% from the second quarter last year. We continue to maintain relatively flat production in this business unit through a drilling program focused primarily on Mississippian opportunities.

Cardium Business Unit

We continue to grow the Cardium business unit, where production averaged 20,180 boepd in the second quarter, representing a 2% decrease over the first quarter and a 27% increase over the second quarter of 2012. The use of pad drilling within the Cardium business unit allowed us to continue completion activities through spring break-up, resulting in 13 wells being completed and 17 wells brought on production in the quarter.

Facilities spending within the Cardium during the second quarter included the expansion of a battery within the Brazeau region. Facility costs increased in the business unit due to scope changes designed to increase overall capacity for the region and cost overruns resulting from adverse surface conditions. As a result of this higher facility spending, we have chosen to defer a portion of our 2013 Cardium drill program and we expect production to remain relatively flat for the balance of the year. The Cardium business unit remains on track to become net cash flow positive commencing in the second half of 2013.

AB/BC Business Unit

Production in our Alberta/BC business unit averaged 3,647 boepd in the quarter, representing a 28% increase over the second quarter of 2012 and an 8% increase over the first quarter of 2013, with the growth driven by our new Swan Hills resource play. Commensurate with this production growth, our liquids weighting continues to increase from 33% in the second quarter of 2012 to 53% this quarter. Activity year-to-date in our emerging light-oil resource plays has resulted in 9 wells being drilled with 3 wells brought on production. The Swan Hills region is expected to become the next growth area for us, and our drilling program will re-commence in the fall with 5 wells planned for the balance of the year.

In addition to our Swan Hills program, we drilled and tested 3 different prospects within our emerging play inventory in the first half of the year. These wells are not producing and the plays require further testing and delineation before we proceed with full development.

FINANCIAL RESULTS

Second quarter production of 46,045 boepd and an operating netback of $50.08/boe resulted in funds flow from operations of $168 million ($0.86 per basic share), a 5% decrease from the preceding quarter due to 6% lower production. Compared to the second quarter of 2012, our funds flow from operations increased 39% on production growth and a higher netback. Our improved netback was a result of an increase in our realized oil price during the quarter driven by higher WTI prices and narrower differentials. For the second quarter of 2013, we realized a 6% discount to WTI, compared to 11% in the first quarter of 2013 and 14% in the second quarter of 2012. While we are currently seeing a general improvement in light oil differentials over 2012, we expect volatility to continue throughout 2013.

Our adjusted net income for the second quarter was a loss of $51 million ($0.26 per basic share), a decrease of $76 million from Q2 2012, primarily due to a lower unrealized gain on risk management contracts, a larger unrealized loss on foreign exchange conversion related to our US dollar term debt and a non-cash loss on assets held for sale.

Capital expenditures, before acquisitions and dispositions, in the second quarter were $117 million, representing a slight increase from the second quarter of 2012 and a 61% decrease from the first quarter of 2013 due to reduced activity as a result of spring break-up. Year-to-date, we have spent $419 million, slightly more than half of our current planned expenditures for 2013. Activity levels during the first half of the year reflect our plan to execute a more balanced program in 2013 to take advantage of favourable winter drilling conditions and to complete facility projects. In comparison, our 2012 capital program was more heavily weighted to the second half of the year as we actively reinvested a portion of our proceeds from asset dispositions following the completion of spring break-up.

Our monthly dividend of $0.08 per share has remained consistent since the Company's inception. During the second quarter, total dividends of $47 million were declared, representing 28% of funds flow from operations. Cash dividends of $35 million were paid, representing 21% of quarterly funds flow from operations, as approximately 27% of shareholders participated in our dividend reinvestment and share dividend plans.

As at June 30, 2013, Lightstream had $1.2 billion of debt drawn on our $1.4 billion credit facility. Effective April 2013, the credit facility was amended to extend the maturity by an additional year to June 2016. All other terms of the facility remain the same, including the tiered covenants and the $100 million accordion feature potentially allowing us to increase the facility size to $1.5 billion.

CURRENT OPERATIONS UPDATE

Average production for the month of July is estimated to be approximately 44,000 boepd, relatively flat to June production as field activities recommenced during the month of July. During the month, 4 wells were drilled and 2 wells were placed on production, leaving 16 wells in inventory at the end of July.

OUTLOOK AND GUIDANCE

With the first half of the year completed, we are updating our 2013 guidance to reflect slight changes to our planned activities. We are reiterating our annual average production guidance of 46,000 to 48,000 boepd, reflecting growth of 8 to 12% over 2012 levels. With the first half of 2013 experiencing average production at the higher end of our forecasted annual average range, we expect production to decline slightly in the third quarter, as the timing of our summer drilling program will result in new wells being brought on-stream later in the quarter, with production again increasing through the fourth quarter.

We now anticipate capital expenditures for 2013 to be $700 to $725 million, approximately 5% higher than the $675 million originally forecast. Changes to our capital spending include an increase in facilities spending of approximately $25 million as a result of cost overruns and scope changes, as well as higher than anticipated drilling and completion costs on exploration wells drilled in our emerging play areas where we are applying innovative techniques to delineate and de-risk new plays. We are also expanding our well optimization budget in the Bakken business unit by approximately $25 million to further capitalize on the success of this activity, and deferring drilling activity in the remainder of the year by approximately 18 net wells, primarily in the Cardium business unit, resulting in an expected total of 111 net wells drilled in 2013.

As a result of the revisions to the capital program, we are holding our average production guidance unchanged for 2013 and reducing our exit production guidance by approximately 4% to 47,000 to 50,000 boepd. This slight reduction in exit rate incorporates the deferral of 18 wells from the drilling program, the majority of which were previously forecast to be brought on production in the fourth quarter.

Based on the changes to our capital plan and an improved outlook for net realized pricing, we are increasing our annual funds flow from operations guidance by approximately $40 million to $680 to $720 million. We continue to expect funds flow from operations in the second half of 2013 to be approximately equal to capital expenditures and cash dividends.

2013 UPDATED GUIDANCE
($000s, except where noted and per share amounts)		2013 Guidance	2013 Revised Guidance	YTD 2013 Actual
Production (annual average)
	Oil and NGL (bbl/d)	39,000 - 41,000	37,700 - 39,300	38,978
	Natural Gas (Mmcf/d)	41 - 43	50 - 52	51
	Total (boe/d)	46,000 - 48,000	46,000 - 48,000	47,553
Exit Production (boe/d)		49,000 - 52,000	47,000 - 50,000	-
Funds Flow from Operations(1)		$645,000 - $680,000	$680,000 - $720,000	$345,198
Funds Flow per share(1)		$3.30 - $3.50	$3.45 - $3.65	$1.78
Declared Dividends per share		$0.96	$0.96	$0.48
Capital Expenditures(2)		$675,000	$700,000 - $725,000	$418,856
Pricing Assumptions:
	Crude oil - WTI (US$/bbl)	90.00	95.00	94.30
	Crude oil - WTI (Cdn$/bbl)	90.00	100.00	95.81
	Corporate oil differential (%)	10	7.5	8
	Natural gas - AECO (Cdn$/mcf)	3.50	3.00	3.37
	Exchange rate (Cdn$/US$)	1.00	1.05	1.02

(1)	Funds flow per share calculation based on 194 million weighted average basic shares outstanding for 2013 in initial guidance and 196 million shares in revised guidance.
(2)	Projected capital expenditures exclude acquisitions and divestitures, which are evaluated separately. Comparatives for 2013 shown prior to acquisition and disposition activity of $6.5 million.
(3)	2013 revised pricing assumptions apply to the second half of 2013.

NAME CHANGE TO LIGHTSTREAM RESOURCES LTD.

On May 22, 2013, PetroBakken Energy Ltd. announced that our shareholders had approved a name change to Lightstream Resources Ltd. In conjunction with the name change, our stock symbol has been replaced with LTS on the Toronto Stock Exchange and LSTMF on the OTC in the United States. This change did not affect any shares held.

The new name, Lightstream Resources Ltd., reflects our strategic focus on effectively developing light oil resource plays to deliver growth and a sustainable dividend for our shareholders. We are committed to maximizing recoveries at the lowest possible cost through the application of innovative ideas, while staying true to our core values and the best interests of our shareholders, stakeholders and employees.

DIVIDEND REINVESTMENT PROGRAM AND SHARE DIVIDEND PLAN

Lightstream has a dividend reinvestment program ("DRIP") in place that is available only to Canadian Lightstream shareholders. Our share dividend plan ("SDP") is now available to Canadian shareholders and most non-Canadian shareholders. The DRIP and the SDP allow shareholders to effectively receive their monthly Lightstream dividends as Lightstream shares at a 5% discount to the market price at the date of the dividend payment.

For further information regarding our SDP and DRIP, please visit Lightstream's website at www.lightstreamresources.com or contact Olympia Trust Company at 403-668-8887, toll free at 1-800-727-4493 or via email at corporateactions@olympiatrust.com.

FINANCIAL & OPERATING TABLES
			Three months ended June 30,				Six months ended June 30
			2013		2012	% Change	2013		2012		% Change
Financial ($000s, except where noted)
Oil and natural gas sales			315,417		240,205	31	630,950		570,566		11
Funds flow from operations (1)			168,212		121,390	39	345,198		306,717		13
	Per share	- basic ($)(1) (2)	0.86		0.65	32	1.78		1.64		9
		- diluted ($)(1) (2) (3)	0.85		0.62	37	1.76		1.57		12
Adjusted Net Income(1)			(50,597	)	25,709	-	(49,041	)	128,318		-
	Per share	- basic ($)(1) (2)	(0.26	)	0.14	-	(0.25	)	0.68		-
		- diluted ($)(1) (2)	(0.26	)	0.14	-	(0.25	)	0.67		-
Dividends(1) (4)			47,313		45,164	5	94,340		90,720		4
Per share ($)(1)			0.24		0.24	-	0.48		0.48		-
Payout ratio(1)			28		37	-	27		30		-
Cash dividends(1) (4)			34,759		16,554	110	67,643		42,277		60
Cash dividend payout ratio(1)			21		14	-	20		14		-
Net capital expenditures(1)			116,982		98,443	19	425,402		(311,643	)	-
Total debt(1)			2,232,656		1,661,167	34	2,232,656		1,661,167		34
Basic common shares, end of period (000)			196,136		187,897	4	196,136		187,897		4
Operations
Operating netback($/boe except where noted) (1)(5)											-
	Oil, NGL and natural gas revenue (6)		74.81		67.89	10	72.90		73.07		-
	Royalties		10.54		9.44	12	9.60		10.80		(11	)
	Production expenses		14.19		13.37	6	13.37		12.95		3
	Operating netback		50.08		45.08	11	49.93		49.32		1
Average daily production
	Oil and NGL (bbls)		37,582		32,236	17	38,978		36,286		7
	Natural gas (mcf)		50,783		38,874	31	51,452		38,597		33
	Total (boe) (5)		46,045		38,715	19	47,553		42,719		11

(1)	Non-GAAP measure. See "Non-GAAP Measures" section within this document.
(2)	2012 balance calculated using shares outstanding by Lightstream prior to the reorganization in December 2012.
(3)	Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date.
(4)	2012 balance represents dividends paid out by Lightstream prior to the reorganization in December 2012. Petrobank Energy and Resources Ltd., which amalgamated with Lightstream pursuant to the reorganization, did not payout out any dividends in the year ending December 31, 2012.
(5)	Six Mcf of natural gas is equivalent to one barrel of oil equivalent ("boe").
(6)	Net of transportation expenses.

INVESTOR CONFERENCE CALL

Management of Lightstream will be holding a conference call for investors, financial analysts, media and any interested persons on Thursday, August 8, 2013 at 9:00 a.m. (MST) (11:00 a.m. EST) to discuss Lightstream's second quarter financial and operating results.

The investor conference call details are as follows:

Live call dial-in numbers: 1-416-695-6623 / 1-800-769-8320

Replay dial-in numbers: 1-905-694-9451 / 1-800-408-3053

Passcode: 4789319

http://www.gowebcasting.com/4656

Lightstream Resources Ltd. is an oil and gas exploration and production company combining light oil Bakken and Cardium resource plays with conventional light oil assets, delivering industry leading operating netbacks, strong cash flows and production growth. Lightstream is applying leading edge technology to a multi-year inventory of Bakken and Cardium light oil development locations, along with a significant inventory of opportunities in the Horn River and Montney gas resource plays in northeast BC. Our strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield.

Non-GAAP Measures. This press release contains financial terms that are not considered measures under IFRS, such as funds flow from operations, adjusted net income, funds flow per share, adjusted net income per share, payout ratio, total debt, operating netback and net capital expenditures. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, funds flow from operations reflects cash generated from operating activities before changes in non-cash working capital. Adjusted net income is determined by adding back any losses or deducting any gains on the derivative liabilities, adding back any losses or deducting any gains on settlement of convertible debentures, and adding back impairments. Payout ratio is determined as dividends paid as a percentage of funds flow from operations. Management considers funds flow from operations, funds flow per share, adjusted net income, adjusted net income per share, and payout ratio important as it helps evaluate performance and demonstrate the ability to generate sufficient cash to fund future growth opportunities, pay dividends and repay debt. Total debt includes bank debt outstanding plus accounts payable less accounts receivable and prepaid expenses plus the full value outstanding on the senior unsecured notes and convertible debentures converted to Canadian dollars at the exchange rate on the period end date less long-term investments. Total debt is used to evaluate PetroBakken's financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Operating netback reflects revenues less royalties, transportation costs, and production expenses divided by production for the period. Net capital expenditures represent capital expenditures, including exploration and evaluation expenditures, less proceeds from asset dispositions. Funds flow from operations, funds flow per share, adjusted net income, adjusted net income per share, payout ratio, total debt, operating netbacks, and net capital expenditures may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations or other measures of financial performance calculated in accordance with IFRS. Further information in respect of these non-GAAP measures is set forth in our MD&A.

Well Counts. All references to well counts are on a net basis.

Forward Looking Statements. Certain information provided in this press release constitutes forward-looking statements. Specifically, this press release contains forward-looking statements relating to financial results, results from operations, future production rates, proposed exploration and development activities (including the number of wells to be drilled, completed and put on production), our drilling prospect inventory, projected capital expenditures, the timing of certain projects and future dividend payments. The forward-looking statements are based on certain key expectations and assumptions, including expectations and assumptions concerning the success of future drilling, completion, recompletion and development activities, the performance of new and existing wells, prevailing commodity prices and economic conditions, the availability and cost of labour and services, timing of pipeline and facilities construction, access to third party facilities and weather and access to drilling locations. Although we believe 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 we 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 (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors, changes in applicable regulatory regimes and health, safety and environmental risks), commodity price and exchange rate fluctuations and general economic conditions. Certain of these risks are set out in more detail in our Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com. Except as may be required by applicable securities laws, PetroBakken assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Natural gas volumes have been converted to barrels of oil equivalent ("boe"). Six thousand cubic feet ("Mcf") of natural gas is equal to one barrel of oil equivalent based on an energy equivalency conversion method primarily attributable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.