Lightstream Resources Ltd.

Lightstream Resources Ltd.

March 03, 2014 22:00 ET

Lightstream Announces 9% Production Growth, $112 Million of Dispositions, Updated Guidance, and 2013 Year-End Reserves

CALGARY, ALBERTA--(Marketwired - March 3, 2014) - Lightstream Resources Ltd. (TSX:LTS) ("Lightstream" or the "Company") is pleased to provide an update on our 2013 fourth quarter and current operations, announce $112 million of asset dispositions, updated 2014 guidance as a result of the dispositions, and report our year-end 2013 reserves. The Company's annual audit of our consolidated financial statements is not yet complete and accordingly all financial and production amounts herein are management's best estimates which are unaudited and subject to change.


  • 2013 annual average production was 46,438 barrels of oil equivalent per day ("boepd"), a 9% increase from our 2012 production average of 42,784 boepd.
  • 2013 fourth quarter average production was 45,521 boepd (80% light oil and liquids weighted), essentially unchanged from Q3 2013 and 4% below Q4 2012.
  • 2013 capital expenditures (before acquisitions and divestitures) were $716 million, 25% below 2012 levels.
  • We drilled 110 wells in 2013, with 44% drilled in the Cardium business unit, 45% in south east Saskatchewan, and the remainder in our Alberta/British Columbia business unit (primarily in our Swan Hills area).
  • 2014 first quarter activity anticipates a total of 46 wells drilled, representing approximately half of our 2014 program, and construction of new facilities, including a 3,500 bopd facility in the Swan Hills area.
  • Initial 2014 asset dispositions have resulted in the sale of, or agreements to sell, approximately 1,700 boepd (66% gas) of non-core production for gross proceeds of $112 million.
  • 2013 activity resulted in total proved ("TP") reserves additions of 11.5 million barrels of oil equivalent ("MMboe") and proved plus probable ("2P") reserves additions of 20.7 MMboe, replacing 122% of 2013 production before asset dispositions and net negative revisions for certain properties when compared to prior year reserve estimates.
  • Our year-end reserves evaluation resulted in 2P reserves of 200.2 MMboe (80% light-oil and liquids weighted) which have a net present value (before tax, discounted at 10%) of $4.1 billion as at December 31, 2013.
  • Our three year finding, development and net acquisition ("FD&A") cost is $31.71/boe for our TP reserves and $30.81/boe for our 2P reserves including net technical revisions and future development costs.
  • Continued success with our enhanced oil recovery ("EOR") initiatives increased our 2P reserves related to our pilot natural gas flood in the Bakken to more than 410 Mboe of reserves, representing a 40% increase for each well under EOR.

Operational Update

In 2013, we focused on deploying a more balanced capital program throughout the year to achieve growth in year-over-year average production. Our efforts achieved an annual average production rate of 46,438 boepd for 2013, representing growth of 9% over our 2012 average production. Our capital spending program for the year was $716 million, within our previously guided range of $700 million to $725 million.

2013 fourth quarter production averaged 45,521 boepd (80% light oil and liquids). Our more level loaded capital program in 2013 took advantage of optimal field conditions during the winter drilling season within some of our areas. As a result, our 2013 production profile was less seasonal with December exit volumes of approximately 45,200 boepd. Our exit volumes were about 4% lower than our guidance, primarily impacted by unplanned production restrictions due to facility constraints and high gathering system pressures in the Cardium, and additional down time with extreme cold weather experienced by all of our business units. December volumes were reduced by approximately 1,200 boepd by these factors. A portion of these volumes have been recovered in the first quarter of 2014, with a majority of the restricted production expected to be recovered by the second half of 2014 through facility de-bottlenecking initiatives.

We drilled a total of 110 wells during 2013. In the Cardium business unit, we drilled 10 wells and placed 14 wells on production in the fourth quarter, bringing our 2013 total to 48 wells drilled and 56 wells brought on production. In southeast Saskatchewan, we drilled 14 wells in the fourth quarter and placed 19 wells on production, bringing our yearly totals to 50 wells drilled and 51 wells on production. In the Swan Hills region, we drilled three wells and placed them on production in the fourth quarter, bringing our 2013 total to nine wells drilled and on production for the year.

2013 Net Wells Drilled

Q1 Q2 Q3 Q4 Total
Cardium 23 2 13 10 48
SE Saskatchewan 22 3 11 14 50
Alberta/BC 8 1 0 3 12
TOTAL 53 6 24 27 110

As we enter 2014, we are very active with drilling and completion operations focused on our core areas in the Bakken, Cardium and Swan Hills. We currently have 11 drilling rigs operational with 5 rigs running in the Cardium, 4 rigs in southeast Saskatchewan and 2 rigs in the Swan Hills area. In the first quarter of 2014, we will drill 22 wells in the Cardium to continue to build on the success we have experienced in this region. We will drill 16 wells in southeast Saskatchewan during the same period and continue our optimization efforts and enhanced oil recovery projects to materially mitigate our Bakken base well declines and replace production. In the Swan Hills area, we will drill eight wells during the first quarter.

Approximately 900 boepd of current production restrictions in the Cardium are being mitigated through infrastructure improvements. We are participating in new oil and gas processing facilities in the Lochend area, which will alleviate existing restrictions on production by the second quarter of 2014. In the West Pembina area we are also adding additional gas handling facilities to deal with line pressure bottlenecks, which have continued to restrict production. Given these infrastructure improvements, we expect to eliminate the production restrictions we are currently experiencing by the second half of 2014.

In the Swan Hills area, we have been active through the winter and have drilled a total of eight wells since October 2013. We will drill three additional wells prior to spring break-up and plan to have all wells on production in May. Well production from our initial producers has averaged in excess of 370 bopd (IP30) through single well battery facilities. To facilitate the transition of Swan Hills into our next growth area, we are presently constructing a 3,500 bopd battery in our core area of Deer Mountain. That facility is expected to be on stream during the second quarter and will eliminate emulsion trucking costs and gas flaring. In addition, the battery will provide a platform for the future activity in the area, which includes plans to drill a further four wells in Deer Mountain in the second half of 2014.

In 2013, we invested exploration capital to drill test wells in our Lutose Slave Point play, at south Cochrane in the Cardium, and on other exploration concepts. We are encouraged by the data gathered at Lutose and plan further drilling to test this prospective light oil resource play. We have 218 sections in this area that, if proved commercial, could significantly impact our production and reserves. At south Cochrane, we drilled and cored a vertical Cardium test well. Although abandoned, the information from this well will help us high-grade the area and provide future potential locations as we extend the Cardium trend.

Our EOR plans continue to expand in all our business units. In the Bakken, we added another natural gas injection well in 2013, bringing our total to four wells now on injection. We also increased total gas injection rates by 33% over the year. We continue to be encouraged by the results we are seeing from these injection schemes, which resulted in additional reserves being recognized at the end of 2013. In 2014, we will be increasing the amount of acreage under injection and expect to have two additional patterns online by year-end, with wells and infrastructure in place for two additional patterns to be added in early 2015. In 2014 we will commence a conventional Mississippian water flood pilot in southeast Saskatchewan as well as initiating pilot patterns targeting both natural gas and water injection in the Cardium. In addition, in the Swan Hills our first horizontal water injection well will be completed and on injection by year-end.

In 2014, we will also continue to build on the success that we have had with our optimization program in southeast Saskatchewan. Operations include millouts, cleanouts, high volume lift installations and casing gas compressor installations. To-date we have optimized over 300 wells, which have shown increased production and mitigated declines. In 2014, we expect to spend $30 million on optimizations in southeast Saskatchewan and this program will be expanded to include the Cardium.

Disposition Activity Update

As previously announced, we are committed to improving our balance sheet strength through the divestment of non-core assets. We are pleased to provide an update on our success so far. To-date, we have sold or are finalizing negotiations for the sale of certain non-core assets in the Alberta/BC business unit and gas weighted assets from our Cardium business unit, where we have retained the Cardium rights. The assets being divested consist of 1,700 boepd of production (66% natural gas weighting), 3 MMboe of 2P reserves, and 41,000 net acres for expected gross proceeds of $112 million.

Transaction metrics for the asset divestures are:

  • Cash flow metric: 11.1x
  • Production metric: $66,000/boepd
  • Reserves metric: $37.56/2P boe ($39.94/2P boe including FDC)

These transactions are consistent with the strategic efforts we outlined in November 2013 and we will continue to target accretive divestitures as we execute our capital plan for 2014.

In November of 2013, we announced that we were going to offer for sale certain fee title and royalty interest lands in southeast Saskatchewan. We had excellent response with multiple interested parties in our process, and although we received a number of compelling bids, the party with the highest bid failed to close their purchase of the properties. Consequently, we are planning to revisit the sale of these assets with market participants in the very near future. Based on the strong interest in this first royalty offering, we have also completed an internal review of additional fee title and royalty interest lands in southeast Saskatchewan and we plan to bring these assets to market in 2014 as well.

2014 Guidance Update

We have updated our 2014 guidance as a result of the recent asset divestments. In 2014, our main priority will be managing and lowering the leverage on our balance sheet through initiatives aimed at reducing our debt to cash flow ratio, while improving our sustainability ratio, maintaining a production platform that can deliver future growth and continuing to pay a dividend. One of our primary initiatives is to undertake asset divestments to generate a targeted $600 million in the next two years, with $300 million of divestitures targeted for this year. We are committed to using the proceeds of any disposition activity to pay down debt.

Our updated guidance in the table below reflects the effect of announced dispositions (net of reduced interest expenses) and an update to our economic forecast, which continues to use a US$95/bbl price for WTI, but now includes a 90 cent Canadian dollar/US dollar exchange rate (95 cents previously) and a $4.00/Mcf AECO gas price ($3.00/Mcf previously). The net effect of these changes has been to reduce our production guidance by 3%, increase our funds flow from operations by 7% and improve our sustainability ratio to 100% (cash outflows prior to divestitures compared to cash inflows).

2014 Guidance

Average Production (boe/d) 43,500 - 45,500 45,000 - 47,000
Exit Production (boe/d) 45,000 - 47,000 46,000 - 48,000
Oil and Liquids Weighting unchanged 80%
Funds Flow(1)
Funds Flow from Operations ('000) $635,000 - $665,000 $595,000 - $620,000
Funds Flow per share(2) $3.19 - $3.34 $2.99 - $3.12
Dividends per share unchanged $0.48
Capital Expenditures(3)
Drill, Complete, Equip and Tie-in ('000) unchanged $350,000 - $370,000
Facilities, Workovers and Optimizations ('000) unchanged $120,000 - $140,000
Land, Seismic and Other ('000) unchanged $55,000 - $65,000
Total Capital Expenditures ('000) unchanged $525,000 - $575,000
  1. Commodity price assumptions include WTI US$95.00/bbl, AECO CDN$4.00/Mcf, foreign exchange rate of US$/CDN$ 0.90, and corporate oil differential of 10%.
  2. Funds flow per share calculation based on 199 million shares outstanding for 2014.
  3. Projected capital expenditures exclude acquisitions, which are evaluated separately.

We remain focused on creating long term value for our shareholders by developing long-life accretive light-oil resource plays that support organic growth of production and reserves. While 2014 represents a transition year in which we will focus on maintaining our production growth platform, improving our balance sheet and long-term sustainability, we believe we will exit 2014 well positioned to capitalize on our extensive asset base to generate long-term growth.


Sproule Associates Limited ("Sproule") has completed their evaluation of Lightstream's reserves, effective December 31, 2013 ("Sproule Evaluation").

Unless otherwise noted, all reserves herein are "Company Interest" reserves, which represent the Company's working interest and royalty interest share of reserves, before deduction of the Company's royalty obligations. All values in this press release are based on Sproule's forecast prices and estimates of future operating and capital costs at December 31, 2013.

Year-end 2013 2P reserves were 200.2 MMboe, after 2.4 MMboe of non-core dispositions, 16.9 MMboe of production, the addition of 20.7 MMboe as a result of capital investment, and 7.9 MMboe in net negative technical revisions. Sproule's net present value of our 2P reserves, discounted at 10%, is $4.1 billion before tax, a slight increase over 2012 due to improved pricing.

During 2013, our capital program resulted in the addition of 20.7 MMboe 2P reserves and 11.5 MMboe of TP reserves. With a total of 16.9 MMboe of reserves produced during the year, this resulted in our 2013 capital program replacing 122% of 2013 production.

For the year ended December 31, 2013, we realized net technical revisions that resulted in 2P reserves being reduced by 7.9 MMboe. The technical revisions to our reserves bookings were primarily comprised of the removal, or reduction, in reserve bookings for areas within southeast Saskatchewan and, to a lesser extent, the Cardium where off-setting production did not economically support the reserve bookings on a go-forward basis.

Inclusive of the net negative technical revisions, our 2013 2P F&D was $57.63/boe (including land) and $56.49/boe (excluding land). We view this as unacceptably high and anomalous due primarily to capital expenditures that did not impact reserves and net negative technical reserve revisions. These revisions accounted for an increase in our 2P F&D of approximately $21.83/boe. Some items of our capital spending during 2013 that were considered to be unique included:

  • Facility cost overruns of $25mm for projects initiated in late 2012;
  • $30mm for pipeline and facility infrastructure to tie-in existing Bakken wells that have been drilled over the past 3 years, resulting in an operating cost savings of over $10/boe for these projects on a go-forward basis. Based on our pace of development in the Bakken we have minimal plans to complete additional infrastructure projects of this magnitude in the future;
  • Initial costs during the evaluation phase of the Swan Hills area program amounted to approximately $15mm of additional capital compared to our current program design; and
  • Drilling capital of $35mm to test new play concepts that did not result in any immediate reserve assignments.

Our 2013 2P F&D before revisions was $35.80/boe. Taking into account all of our expenditures and reserve revisions, our three-year weighted average F&D cost, including land, is $33.07/boe, generating an operating recycle ratio of 1.5 times, based on a $50.80/boe netback. We are targeting 2014 F&D costs to be within our historical range of $25.00/boe to $30.00/boe, as we do not expect the above mentioned 2013 costs to be recurring.

2P reserves in the Cardium business unit increased from 93.7 MMboe in 2012 to 95.4 MMboe in 2013, replacing 124% of production. Large positive revisions were also made due to performance and increased gas to oil ratios in the area. In 2013, 2P FD&A costs for this business unit were $24.95/boe (including revisions), generating an operating recycle ratio of 1.9 times based on our operating netback for the business unit of $47.54/boe. We expect the Cardium business unit to continue to be a key source of growth, with a development drilling inventory of over 530 net locations, of which 202 net locations were included in the Sproule Evaluation.

2P reserves in the Bakken business unit (before dispositions) were down slightly in 2013, resulting in year-end 2P reserves of 72.8 MMboe. The potential for future EOR-related reserve growth in the Bakken is encouraging after receiving initial 2P reserve recognition for the early stage success of our pilot natural gas flood. We now have 415 Mboe of reserves added that can be attributed to our EOR program. At year-end, we had an inventory of over 900 net locations in the business unit, of which 275 net locations were included in the Sproule Evaluation.

Forecast Prices(1)
As at December 31, 2013

Company Gross(2)
Company Interest(4)
Total Oil
Natural Gas
Proved Developed Producing 56,992 5,189 98,904 78,665 757 79,422
Total Proved 90,042 7,987 156,732 124,151 822 124,973
Proved + Probable (2P) 146,357 12,527 240,985 199,048 1,169 200,217
Net Present Value - Before Tax ($millions)(5)(6)
Forecast Prices(1)
As at December 31, 2013
0% 5% 10%
Proved Developed Producing $3,504 $2,758 $2,297
Total Proved 4,811 3,584 2,840
Proved + Probable (2P) $8,177 $5,538 $4,112
Net Present Value - After Tax ($millions)(5)(6)
Forecast Prices(1)
As at December 31, 2013
0% 5% 10%
Proved Developed Producing $3,251 $2,604 $2,197
Total Proved 4,217 3,193 2,563
Proved + Probable (2P) $6,696 $4,617 $3,477
Company Interest Reserve Reconciliation (Mboe)(4)
Forecast Prices(1)
As at December 31, 2013
Developed Total Proved+
Producing Proved Probable
Lightstream reserves at December 31, 2012 81,309 131,359 206,758
2013 production (16,950) (16,950) (16,950)
Net dispositions (234) (1,526) (2,430)
Net additions and revisions 15,297 12,090 12,839
Lightstream reserves at December 31, 2013 79,422 124,973 200,217
Lightstream year-over-year increase in reserves (2%) (5%) (3%)
Lightstream production replacement(7)(8) 90% 71% 76%
  1. Based on the Sproule price forecast effective December 31, 2013.
  2. Company Gross reserves, which represent the Company's working interest share of reserves excluding the Company's royalty interests in reserves and before deduction of royalty obligations.
  3. Royalty interest reserves owned by the Company.
  4. "Company Interest" reserves, which represent the Company's working interest share of reserves including the Company's royalty interests in reserves and before deduction of the Company's royalty obligations.
  5. Company working interest reserves value plus royalties received less royalties and burdens.
  6. Estimated values of future net revenue disclosed in this press release do not represent fair market values.
  7. Represents total reserve additions, including revisions and before dispositions, as a percentage of 2013 production.
  8. The disclosures required in accordance with National Instrument 51-101 of the Canadian Securities Administrators will be available in the Company's Annual Information Form to be filed on the SEDAR website at prior to March 31, 2014.
F&D and FD&ACosts(1)
For the year ended December 31, 2013
F&D Acquisitions & Dispositions FD&A(2)
Capital expenditures (unaudited-$000s)
Capital expenditures $715,913 - $715,913
Acquisition/(Disposition) capital - 3,188 3,188
Total capital 715,913 3,188 719,101
Less: Land value 14,649 - 14,649
Total capital excluding land value $701,264 $3,188 $704,452
Change in FDC ($000s)
Total Proved $(48,273) $(31,082) $(79,355)
Proved + Probable (2P) $23,925 $(60,732) $(36,807)
Total costs ($000s)
Total Proved $667,640 $(27,894) $639,746
Proved + Probable (2P) $739,838 $(57,544) $682,294
Net reserve additions (mboe)
Total Proved 12,089 (1,526) 10,563
Proved + Probable (2P) 12,838 (2,430) 10,408
F&D and FD&A costs ($/boe) (including land)
Total Proved $55.23 $(18.28) $60.56
Proved + Probable (2P) 57.63 (23.68) 65.55
FD&A costs ($/boe) (excluding land)
Total Proved 54.02 (18.28) 59.18
Proved + Probable (2P) $56.49 $(23.68) $64.15
For the year-ended Dec. 31, 2012
F&D and FD&A costs ($/boe) (including land)
Total Proved $26.83 $(64.59) $11.45
Proved + Probable (2P) 26.74 (43.38) 11.91
F&D and FD&A costs ($/boe) (excluding land)
Total Proved 26.19 (64.59) 10.55
Proved + Probable (2P) $26.06 $(43.38) $10.63
For the 3 years-ended Dec. 31, 2013(2)
F&D and FD&A costs ($/boe) (including land)
Total Proved $36.22 $(59.86) $31.71
Proved + Probable (2P) 33.07 (41.58) 30.81
F&D and FD&A costs ($/boe) (excluding land)
Total Proved 35.34 (59.86) 30.66
Proved + Probable (2P) $32.31 $(41.58) $29.85
  1. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
  2. The Company uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.
  3. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6 thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

2013 Fourth Quarter and Year-End Financial Results and Conference Call

We will be releasing our audited 2013 fourth quarter and year-end financial results before markets open on Tuesday, March 11, 2014. Management will also be hosting a conference call for investors, financial analysts, media and any interested persons on Tuesday, March 11, 2014, at 9:00 a.m. (Mountain Time) (11:00 a.m. Eastern Time) to discuss our 2013 fourth quarter and annual 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

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 other emerging resource play opportunities. Our strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield.

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, future finding and development costs, the anticipated completion of asset dispositions, 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 market for asset dispositions and the ability of counterparties to close on dispositions, 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, risks that asset dispositions cannot be completed, 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 Except as may be required by applicable securities laws, Lightstream 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.

BOEs. 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.

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

Contact Information

  • Lightstream Resources Ltd.
    John D. Wright
    President and Chief Executive Officer

    Lightstream Resources Ltd.
    Peter D. Scott
    Senior Vice President and Chief Financial Officer

    Lightstream Resources Ltd.
    William A. Kanters
    Vice President, Capital Markets
    403.218.6075 (FAX)