Crude Oil ( ) Brent Crude ( ) Natural Gas ( ) S&P 500 ( ) PHLX Oil ( )

Lightstream Resources Ltd. (the “Company” or “Lightstream”) (LTS.TO) is pleased to announce our third quarter financial and operating results and provide an update on our Swan Hills program.

THIRD QUARTER FINANCIAL & OPERATING HIGHLIGHTS

  • In the third quarter, we exceeded our asset divestiture goals with the sale of the remainder of our southeast Saskatchewan conventional business unit for gross proceeds of $476 million, resulting in total 2014 proceeds from non-core dispositions of $729 million.
  • Year-to-date, we have reduced our debt by $716 million through divestiture proceeds and excess cash flow, a 31% decrease from year-end 2013 levels.
  • Including the impact of our non-core asset sales this year, third quarter production averaged 38,837 barrels of oil equivalent per day (“boepd”) (78% light oil and liquids), a 9% decrease from the second quarter of 2014.
  • Our operating netback for the third quarter was $48.67/boe, an 11% decrease from the third quarter of 2013, mainly due to weaker commodity prices and slightly increased production costs.
  • Funds flow from operations was $131 million ($0.65 per basic share) for the quarter, representing a 27% decrease from the third quarter of 2013 as a result of lower production and weakened commodity prices.
  • Capital expenditures before acquisitions and dispositions totalled $90 million in the third quarter, a 36% decrease from the same quarter a year ago, and resulted in 18 wells drilled, 8 wells brought on production and 14 wells in inventory at the end of the quarter.
  • We completed our Swan Hills area technical review and confirmed that this area remains a long-term growth platform for the Company.

SUMMARY OF RESULTS

Three months ended
September 30,
Nine months ended
September 30,
2014 2013 2014 2013
Oil and natural gas sales 269,177 331,814 920,963 962,764
Funds flow from operations (1) 130,950 179,713 482,954 524,911
Per share – basic ($)(1) 0.65 0.91 2.41 2.70
Adjusted Net income (loss)(1) 6,935 52,031 89,536 2,990
Per share – basic ($)(1) 0.03 0.26 0.45 0.02
Capital Expenditures(2) 90,164 141,124 350,696 559,980
Net Capital Expenditures(1) (372,259 ) 139,212 (363,830 ) 564,614
Total debt (1) 1,557,817 2,195,808
Dividends per share ($) 0.12 0.24 0.36 0.72
Common Shares, end of period (000) (3) 200,466 198,520
Operating netback ($/boe) (1) (4) 48.67 54.75 54.24 51.50
Average daily production (boe) (4) 38,837 45,160 41,750 46,746
(1) Non-GAAP measure. See “Non-GAAP Measures” section.
(2) Prior to asset acquisitions and dispositions.
(3) Denotes basic common shares outstanding.
(4) Six Mcf (thousand cubic feet) of natural gas is equivalent to one barrel of oil equivalent (“boe”).

OPERATING RESULTS

Our third quarter average production of 38,837 boepd (78% light oil and liquids) was comprised of 17,699 boepd from the Cardium business unit, 16,941 boepd from our southeast Saskatchewan business units and 4,197 boepd from the AB/BC business unit. The decrease in production compared to the prior years is largely due to the asset disposition activity in 2014, representing a total of 6,315 boepd, and reduced capital spending. The production impact of the dispositions in the third quarter was approximately 3,400 boepd. Production expenses were $14.85/boe in the third quarter, slightly higher in 2014 than in 2013 due to higher workover costs but lower than our internal estimates and guidance.

Average Daily Production

Three months ended
September 30, 2014
Nine months ended
September 30, 2014
Business Unit Oil & NGL
(bbl/d)
Gas
(Mcf/d)
Total
(boe/d)
Oil & NGL
(bbl/d)
Gas
(Mcf/d)
Total
(boe/d)
Bakken 12,740 6,356 13,799 13,775 6,115 14,794
Conventional (SE SK) 2,994 887 3,142 4,111 1,261 4,321
Cardium (central AB) 11,541 36,944 17,699 12,577 36,250 18,619
Alberta/BC 2,928 7,615 4,197 2,698 7,910 4,016
30,203 51,802 38,837 33,161 51,536 41,750

In the third quarter, capital expenditures before acquisitions and dispositions totaled $90 million. This is 36% lower than the third quarter of the prior year due to a reduced capital program for 2014. During the quarter, we drilled 18 wells, brought 8 wells on production, and had 14 wells left in inventory at the end of the quarter. To date in 2014, we have drilled 69 wells and brought 62 wells on production. Capital activity will increase in the fourth quarter to take advantage of optimal drilling conditions. We plan to drill 26 wells in the fourth quarter representing approximately 27% of our 2014 drilling program.

Third Quarter 2014 Drilling Activity

Drilled Completed On
Production
Inventory(1)
Business Unit Gross Net Gross Net Gross Net Gross Net
Bakken 9 6 4 3 2 2 10 7
Conventional (SE SK) 2 2 2 2
Cardium (central AB) 18 10 10 6 10 6 9 5
Alberta/BC
Total 29 18 14 9 12 8 21 14
(1) Inventory refers to the number of wells pending completion and/or tie-in at September 30, 2014.

Southeast Saskatchewan Business Units Update

Production in the southeast Saskatchewan business units averaged 16,941 boepd in the quarter, representing a 19% decrease from the third quarter of 2013. The decline is due principally to a 57% lower capital program resulting in significantly reduced drilling activity this year as well as area asset dispositions totaling 1,315 boepd for the quarter. During the third quarter we brought 2 wells on production with 7 Bakken wells remaining in inventory.

Cardium Business Unit

Production in the Cardium during the third quarter averaged 17,699 boepd, representing a 14% decrease from the third quarter of 2013. This decrease was driven by divestitures representing 1,200 boepd of production, 35% lower capital expenditures year-over-year, 2 non-operated Falher wells producing materially below their capacity, and mechanical issues with 5 Cardium wells within the business unit. The Falher wells are presently flowing at much higher rates and we remediated 3 of the Cardium wells improving production. Commencing in the third quarter, we implemented minor enhancements under our drilling program to our completion techniques which eliminate these mechanical issues. During the quarter, we also invested in facilities and infrastructure to alleviate restrictions on solution gas volumes. In total we brought 6 wells on-stream, leaving 5 wells in inventory as of September 30, 2014.

Alberta/BC Business Unit

In our Alberta/BC business unit, third quarter production averaged 4,197 boepd, which represents a 12% increase relative to the third quarter of 2013, despite the disposition of 500 boepd during the first quarter of 2014 through asset sales. The increase is largely due to 7 wells we brought on stream in the Swan Hills during the second quarter when our new oil facility was commissioned.

Production from the 7 new wells brought on stream during the second quarter did not meet the production performance expectations set by our 2012/2013 Swan Hill’s drilling program. As a result, we suspended drilling in this play pending an internal review to understand performance differences. This review indicates production results from our recent wells were impacted by completion and flow-back practices rather than geological considerations. The delayed start-up of the battery, combined with equipment constraints, resulted in completion fluid being left in the wells for an extended period of time, creating formation damage and compromising production performance. These practices will be eliminated from our future development program in the area. With the confirmation of our geological and reservoir modelling, the Swan Hills continues to remain a long term growth area. Due to recent impairments to third party gas infrastructure, drilling in the area is not expected to resume before the second half of 2015.

FINANCIAL RESULTS

In 2014, we sold $729 million of non-core assets, $476 million of which were sold during the third quarter. We used the proceeds from these dispositions to repay amounts outstanding under the credit facility and the lending amount was reduced from $1.4 billion to $1.15 billion. In 2014, we reduced our total debt by 31% and we expect annual interest savings of at least $25 million. At September 30, 2014, we had approximately $660 million of available liquidity.

Funds flow from operations during the third quarter was $131 million ($0.65 per basic share), which is 27% lower than the third quarter of 2013 due to lower production levels and a decreased operating netback of $48.67/boe.

Our adjusted net income for the third quarter was $6.9 million ($0.03 per basic share) compared to $52 million in third quarter 2013. The decrease in net income compared to the same quarter in 2013 is primarily due to an unrealized foreign exchange loss compared to a previous gain, lower sales volumes and lower realized prices, partially offset by an unrealized gain on risk management contracts compared to a loss previously, a higher gain on asset dispositions and lower depletion and depreciation.

Our monthly dividend was $0.04 per share during the third quarter, which resulted in total dividends of $24 million, representing 19% of funds flow from operations. For the first nine months of 2014, we have achieved a sustainability ratio of 88% (before divestiture proceeds) which is ahead of our plan and significantly improved over the 134% ratio for the prior year period.

At the end of the third quarter, we had $1.56 billion in total debt, including $489 million of debt drawn on our $1.15 billion secured termed credit facility, US$856 million of senior unsecured notes and convertible debentures of US$6.5 million.

UPDATED GUIDANCE

($000s, except where noted and per share amounts) 2014 Guidance
(September 2, 2014)
(1)
2014 Revised
Guidance
(October 30, 2014)
Production (annual average)
Total (boe/d) 40,000 – 42,000 40,000 – 41,000
Natural Gas Weighting 22 % 22 %
Exit Production (boe/d) 36,500 – 39,500 36,000 – 37,000
Funds Flow from Operations $615,000 – $645,000 $575,000 – $595,000
Funds Flow per share $3.08 – $3.23 $2.88 – $2.98
Declared Dividends per share $0.48 $0.48
Capital Expenditures $485,000 – $535,000 $480,000 – $500,000
Pricing Assumptions:
Crude oil – WTI (US$/bbl) 95.00 80.00
Crude oil – WTI (Cdn$/bbl) 105.55 88.89
Corporate oil differential (%) 10 10
Natural gas – AECO (Cdn$/mcf) 4.00 4.00
Exchange rate (Cdn$/ US$) 1.11 1.11

On September 2, 2014 we updated our guidance to reflect dispositions to date. We have completed $729 million of non-core asset dispositions in 2014 representing 6,315 boepd and used the proceeds to reduce debt.

To reflect actual results for the first nine months of the year, and our expectations for the fourth quarter, we are reducing the upper range on full year average guidance to 40,000-41,000 boepd (78% liquids). Bakken business unit production is performing ahead of our expectations; however, we have slightly reduced the range on exit guidance to 36,000-37,000 boepd due to minor program delays pushing on-stream dates for 4 Cardium wells into 2015. As a result, we have reduced full year capital expenditure guidance to a range of $480 million to $500 million.

We continually monitor the commodity pricing environment and given the recent decline in global commodity prices, we are reducing our outlook for WTI for Q4 2014 from $95.00/bbl to $80.00/bbl. We now expect full year funds flow to range from $575 million to $595 million. Using the mid-points of our revised funds flow and capital guidance, we continue to expect a sustainability ratio of approximately 100% for 2014.

THIRD QUARTER FINANCIAL INVESTOR CONFERENCE CALL

Management of Lightstream will be holding a conference call for investors, financial analysts, media and any interested persons on October 31, 2014 at 9:00 a.m. (MST) (11:00 a.m. EST) to discuss our third quarter financial and operating results.

The investor conference call details are as follows:

Live call dial-in numbers: 1-416-340-8530/ 1-800-766-6630

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

Passcode: 5694926

www.gowebcasting.com/5248

FINANCIAL & OPERATING TABLES

Three months ended
September 30,
Nine Months ended
September 30,
2014 2013 %
Change
2014 2013 %
Change
Financial ($000s, except where noted)
Oil and natural gas sales 269,177 331,814 (19 ) 920,963 962,764 (4 )
Funds flow from operations (1) 130,950 179,713 (27 ) 482,954 524,911 (8 )
Per share
– basic ($)(1) 0.65 0.91 (29 ) 2.41 2.70 (11 )
– diluted ($)(1) (2) 0.64 0.90 (29 ) 2.37 2.66 (11 )
Adjusted Net Income (loss)(1) 6,935 52,031 (87 ) 89,536 2,990 2,895
Per share
– basic ($)(1) 0.03 0.26 (88 ) 0.45 0.02 2,150
– diluted ($)(1) (2) 0.03 0.26 (88 ) 0.44 0.02 2,100
Dividends(1) 24,370 47,876 (49 ) 73,019 142,216 (49 )
Per share ($)(1) 0.12 0.24 (50 ) 0.36 0.72 (50 )
Payout ratio(1) 19 % 27 % 15 % 27 %
Cash dividends(1) 24,370 32,189 (24 ) 73,019 99,832 (27 )
Cash dividend payout ratio(1) 19 % 18 % 15 % 19 %
Capital Expenditures(3) 90,164 141,124 (36 ) 350,696 559,980 (37 )
Net capital expenditures(1) (372,259 ) 139,212 (363,830 ) 564,614
Total debt(1) (4) 1,557,817 2,195,808 (29 )
Basic common shares, end of period (000) 200,466 198,520 1
Operations
Operating netback ($/boe except where noted) (1)(5)
Oil, NGL and natural gas revenue (6) 74.84 79.36 (6 ) 80.32 75.00 7
Royalties 11.32 11.36 11.74 10.17 15
Production expenses 14.85 13.25 12 14.34 13.33 8
Operating netback 48.67 54.75 (11 ) 54.24 51.50 5
Average daily production (boe/d)
Oil and NGL (bbl/d) 30,203 35,445 (15 ) 33,161 37,787 (12 )
Natural gas (mcf/d) 51,802 58,290 (11 ) 51,536 53,756 (4 )
Total (boe/d) (5) 38,837 45,160 (14 ) 41,750 46,746 (11 )
(1) Non-GAAP measure. See “Non-GAAP Measures” section within this document.
(2) Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date.
(3) Prior to asset acquisitions and dispositions.
(4) Total debt is calculated as secured credit facility outstanding plus accounts payable less accounts receivable, prepaid expense and long-term investments 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.
(5) Six Mcf of natural gas is equivalent to one barrel of oil equivalent (“boe”).
(6) Net of transportation expenses.