Long Run Exploration Ltd.
TSX : LRE

Long Run Exploration Ltd.

March 04, 2015 18:22 ET

Long Run Exploration Ltd. Announces Reserves, Financial and Operating Results for the Year Ended December 31, 2014

CALGARY, ALBERTA--(Marketwired - March 4, 2015) - Long Run Exploration Ltd. ("Long Run" or the "Company") (TSX:LRE) announces reserves, financial and operating results for the year ended December 31, 2014.

2014 ANNUAL HIGHLIGHTS

  • Established the Deep Basin Cardium core area through two strategic acquisitions for total consideration of $576 million. The Deep Basin transactions provide a key entry point into the Pine Creek, Kakwa and Wapiti areas of Alberta and add ownership of gathering and processing infrastructure.

  • Executed a focused development program, drilling 100.5 net wells. Net capital expenditures of $275 million, excluding the Deep Basin acquisitions, concentrated on our Peace River Montney, Deep Basin Cardium and Redwater Viking core areas.

  • Averaged 31,168 Boe/d of production, a 24% increase from 25,094 Boe/d in 2013. The production increase resulted from the Deep Basin acquisitions and our 2014 drilling program.

    The production average for the acquired Deep Basin assets was approximately 5,600 Boe/d, excluding new wells drilled on the acquired lands. The increase in our 2014 production was tempered by third party restrictions and plant outages experienced in the latter half of the year which reduced production by approximately 960 Boe/d. In the first quarter of 2015, we expect third party outages to be materially reduced.

  • Increased proved plus probable reserves at December 31, 2014 by 75% to 170,625 MBoe from 97,683 MBoe in 2013 as a result of the Deep Basin acquisitions and Long Run's 2014 drilling program.

    The increase in reserves was attributable to a 6% (2,347 MBoe) increase in oil reserves, a 475% (23,338 MBoe) increase in natural gas liquids ("NGLs") reserves and an 86% (283,542 MMcf) increase in natural gas reserves. Total proved reserves increased 65% to 103,544 MBoe in 2014.

  • Increased our reserve life index by 41% from 10.2 years in 2013 to 14.4 years in 2014, based on proved plus probable reserves.

  • Generated finding, development and acquisition ("FD&A") costs, including the change in future development capital ("FDC"), of $21.54/Boe for proved reserves and $15.78/Boe for proved plus probable reserves.

  • Achieved a proved plus probable FD&A recycle ratio of 2.0x.

  • Generated funds flow from operations of $291.9 million, a 27% increase over $230.1 million in 2013. The increase was primarily due to higher production volumes and realized pricing, partially offset by higher royalty expense and higher operating costs associated with increased production volumes.

  • Realized an increased oil price including derivatives of $84.89/Bbl compared to $78.13/Bbl in 2013, reflecting an increase in the U.S. dollar exchange rate and lower differentials, partially offset by a weaker WTI oil benchmark price.

    Our realized NGL price decreased to $51.24/Bbl from $72.45/Bbl in 2013 as a result of the change in our product mix due to the Deep Basin acquisitions and the reduced market prices in the second half of 2014.

    Our realized natural gas price including derivatives increased to $4.52/Mcf from $3.70/Mcf in 2013, primarily attributable to a stronger AECO benchmark price.

  • Recorded a net loss of $190.4 million compared to net earnings of $24.3 million in 2013. The loss resulted primarily from property impairments of $300 million after tax due to the decline in future commodity price forecasts at December 31, 2014.

SUMMARY OF FOURTH QUARTER & ANNUAL RESULTS

Three months ended December 31 Year ended December 31
($000s, except per share amounts or unless otherwise noted) 2014 2013 2014 2013
Funds flow from operations1 68,178 55,934 291,856 230,109
Per share, basic 1 0.35 0.45 1.85 1.83
Per share, diluted1 0.35 0.44 1.85 1.83
Net earnings (loss) (258,652) (5,531) (190,395) 24,265
Per share, basic (1.34) (0.04) (1.21) 0.19
Per share, diluted (1.34) (0.04) (1.21) 0.19
Production
Oil (Bbl/d) 12,130 13,251 12,590 11,890
NGLs (Bbl/d) 5,609 1,520 3,076 1,342
Liquids (Bbl/d) 17,739 14,771 15,666 13,232
Natural Gas (Mcf/d) 112,576 73,392 93,008 71,170
Total (Boe/d) 36,502 27,003 31,168 25,094
Prices, including derivatives
Oil ($/Bbl) 79.35 71.14 84.89 78.13
NGLs ($/Bbl) 30.02 69.21 51.24 72.45
Liquids ($/Bbl) 63.75 70.94 78.29 77.55
Natural Gas ($/Mcf) 4.15 4.04 4.52 3.70
Total ($/Boe) 43.92 49.78 53.00 51.63
Revenues, before royalties 133,354 124,816 610,896 475,562
Capital expenditures 70,094 41,637 304,031 276,571
Net acquisitions (divestitures)2 (1,797) 86,328 (28,674) 108,762
Net capital expenditures2 68,297 127,965 275,357 385,333
Total assets 1,939,706 1,403,344 1,939,706 1,403,344
Bank loan 611,717 423,553 611,717 423,553
Net debt1 739,598 452,155 739,598 452,155
Non-current financial liabilities, excluding bank loan 68,230 3,876 68,230 3,876
1See Non-GAAP Measures section.
2Excludes the two Deep Basin acquisitions.

2014 YEAR END RESERVES

Long Run's 2014 year end reserves were evaluated by independent reserves evaluator Sproule Associates Limited ("Sproule"). Reserve estimates were prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the summary below represents Long Run's gross reserves, which are the Company's interest before deduction of royalties and without including any of our royalty interests. The reserve estimates set forth below are based upon the Sproule reserve report dated March 4, 2015. Long Run's successful drilling program in 2014 combined with the strategic Deep Basin acquisitions executed over the course of the year contributed to substantial reserve growth for our shareholders.

Additional information with respect to the Company's reserves as at December 31, 2014 will be contained in the Company's annual information form for the year ended December 31, 2014 which will be filed on SEDAR at www.sedar.com on or about March 4, 2015.

December 31, 2014 Reserves(1)
Oil
(MBbl)
NGLs
(MBbl)
Natural Gas
(MMcf)
Total
(MBoe)
Proved
Proved producing 15,164 7,799 194,693 55,412
Proved non-producing 304 818 19,975 4,451
Proved undeveloped 11,171 7,899 147,669 43,681
Total Proved 26,639 16,516 362,336 103,544
Probable 13,598 11,731 250,508 67,081
Total Proved Plus Probable 40,237 28,247 612,844 170,625
(1) Amounts may not add due to rounding
Reserves Reconciliation(1)
(MBoe) Proved Probable Proved plus Probable
December 31, 2013 62,692 34,991 97,683
Extensions 2,132 3,916 6,047
Infill drilling 3,336 1,058 4,394
Technical revisions 2,384 (4,285) (1,902)
Discoveries - - -
Acquisitions 47,241 32,485 79,726
Dispositions (2,035) (953) (2,988)
Economic factors (830) (130) (960)
Production (11,376) - (11,376)
December 31, 2014 103,544 67,081 170,625
(1) Amounts may not add due to rounding

Reserves Pricing

2014 2013
WTI Oil
(US$/Bbl)
AECO Gas
(CDN$/Mcf)
WTI Oil
(US$/Bbl)
AECO Gas
(CDN$/Mcf)
2014 - - 95.72 4.01
2015 64.17 3.38 93.62 4.17
2016 76.67 3.83 92.25 4.35
2017 83.33 4.06 96.01 4.81
2018 - 2021 87.08 - 96.59 4.41 - 5.18 96.59 - 100.80 4.99 - 5.38
2022 - 2025 98.36 - 103.88 5.36 - 5.80 102.64 - 108.40 5.48 - 5.80
Remainder +1.8%/yr +1.8%/yr +1.8%/yr +1.8%/yr

Forecast prices, inflation, and exchange rates utilized by Sproule in its evaluation were an average of the forecast prices, inflation and exchange rates as published by Sproule, GLJ Petroleum Consultants Ltd., and McDaniel & Associates Consultants Ltd., as at December 31, 2014.

Summary of Before Tax Net Present Values of Future Net Revenue (1)

Before Tax Net Present Value ($000s)
Discount Rate 0% 5% 10% 15% 20%
Proved producing 1,121,103 906,484 768,299 670,898 598,224
Proved non-producing 76,595 57,659 46,135 38,322 32,683
Proved undeveloped 561,912 328,271 191,059 105,860 50,808
Total Proved 1,759,609 1,292,414 1,005,493 815,081 681,715
Probable 1,517,695 938,937 636,712 458,059 343,584
Total proved plus probable 3,277,304 2,231,351 1,642,205 1,273,140 1,025,299
(1) Net present values of future net revenue does not represent fair market value

Finding and Development ("F&D") and Finding, Development and Acquisition ("FD&A")

Including change in FDC
($/Boe, except recycle ratios)
2014 2013 3 Year Average
F&D Cost(1)
Total Proved Plus Probable 35.52 21.85 40.72
Total Proved 34.72 26.77 39.96
F&D Recycle Ratio(2)
Total Proved Plus Probable 0.9 1.4 0.7
Total Proved 0.9 1.1 0.8
FD&A Cost(3)
Total Proved Plus Probable 15.78 23.21 15.85
Total Proved 21.54 28.19 21.25
FD&A Recycle Ratio(2)
Total Proved Plus Probable 2.0 1.3 1.9
Total Proved 1.5 1.0 1.4
(1) Calculated as the total exploration and development costs plus the total change in FDC divided by the total change in reserves, including reserve revisions. 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.
In 2014, our primary focus was on completing a series of acquisitions to create our new Deep Basin area. Development capital focused on infill drilling, continuing work on waterflood projects as well as plant and facility construction.
(2) Recycle ratio is calculated as average annual operating netback divided by F&D or FD&A costs. Operating netback is calculated as revenue, including realized gains/losses on financial derivatives, minus royalties, operating expenses and transportation costs.
(3) Long Run calculates FD&A costs which incorporate both the costs and associated reserve additions related to acquisitions net of any dispositions during the year. The acquisitions include the announced purchase price of corporate acquisitions rather than the amounts allocated to property, plant and equipment for accounting purposes. In 2013 and 2012, the acquisition costs related to corporate acquisitions reflect the fair market value. Since acquisitions can have a significant impact on Long Run's annual reserve replacement costs, the Corporation believes the FD&A costs provide a more meaningful portrayal of Long Run's cost structure.

FOURTH QUARTER FINANCIAL UPDATE

  • Funds flow from operations for the fourth quarter of 2014 totaled $68.2 million, an increase of 22% from $55.9 million in 2013. The increase was attributable to higher production volumes and a realized gain on financial derivatives, partially offset by lower oil and NGL prices and higher operating costs associated with the increased production volumes. The fourth quarter funds flow from operations for 2014 included the operating and financial results from the Deep Basin acquisitions.

  • The net loss for the fourth quarter of 2014 was $258.7 million, compared to a net loss of $5.5 million in 2013. The 2014 net loss primarily resulted from year end impairment charges of $300 million after tax due to the decline in future commodity price forecasts at December 31, 2014.

  • Long Run's operating netback of $25.04/Boe and corporate netback of $20.33/Boe in the fourth quarter reflect lower commodity prices, partially offset by a realized gain on financial derivatives and lower royalties compared to the fourth quarter of 2013.

    Long Run's realized oil price excluding derivatives decreased to $66.62/Bbl from $73.72/Bbl in 2013, reflecting the weaker WTI oil benchmark price, partially offset by an increase in the U.S. dollar exchange rate and lower differentials. Including a gain on derivatives of $12.73/Bbl, our 2014 realized oil price was $79.35/Bbl.

    Our realized NGL price decreased to $30.02/Bbl from $69.21/Bbl in 2013 as a result of the change in our product mix due to the Deep Basin acquisitions and the reduced market prices in the second half of 2014.

    Our realized natural gas price excluding derivatives increased to $4.13/Mcf from $3.73/Mcf in 2013, primarily attributable to stronger benchmark AECO natural gas prices and reflecting the premiums received for the liquids content included in our natural gas production. Including a gain on derivatives of $0.02/Mcf, our 2014 realized natural gas price was $4.15/Mcf.

    Operating costs in the fourth quarter averaged $12.71/Boe, improving from $13.36/Boe in 2013 primarily due to the addition of the lower operating cost Deep Basin assets. Fourth quarter general and administrative costs averaged $2.32/Boe. For 2015, we estimate operating costs to be approximately $13.50/Boe and general and administrative costs to be approximately $2.50/Boe.

  • At December 31, 2014, Long Run's net debt of $739.6 million increased $287.4 million from December 31, 2013, resulting from funding a portion of the Deep Basin acquisitions with debt. Net debt to funds flow from operations at December 31, 2014 was 2.7 times. The ratio was calculated based on fourth quarter funds flow annualized and reflects the lower commodity prices experienced in the quarter. With the goal of improving liquidity in the current commodity price environment, the Company is currently planning to reduce our debt by $100.0 million in 2015, primarily through reduced capital spending, the suspension of our monthly dividend and selective asset dispositions.

FOURTH QUARTER OPERATIONAL UPDATE

  • Fourth quarter production for 2014 averaged 36,502 Boe/d (49% oil and NGLs), which represents an increase of 9,499 Boe/d from 27,003 Boe/d (55% oil and NGLs) in 2013. The production increase resulted from the addition of our Deep Basin acquisition properties and our successful development drilling over the past year. The Deep Basin acquisition properties added approximately 11,400 Boe/d of production in the fourth quarter.

    Third party outages continued to affect production in the quarter. Extended outages reduced production by approximately 2,200 Boe/d with longer than expected third party outages at both Kakwa and Wapiti as well as extended downtime resulting from a third party gas pipeline replacement at Cherhill. In the first quarter of 2015, we expect third party outages to be materially reduced with the completion of the facility expansion at Kakwa and the infrastructure modifications at Cherhill.

  • Capital expenditures of $70.1 million in the fourth quarter of 2014 focused on the development of our Deep Basin core area and included $15 million of capital originally planned for the first quarter of 2015. First quarter 2015 net capital expenditures have been reduced accordingly. Fourth quarter 2014 capital included Deep Basin facility costs spent to provide flexibility for future development and reduce reliance on third party processing. The Company drilled 11.0 wells (10.0 net wells) in the quarter with a 100% success rate, including 8 wells in the Deep Basin Cardium, 1 well in the Peace River Montney and 1 well in the Redwater Viking.

2015 FINANCIAL UPDATE

  • In response to the depressed commodity price environment, Long Run has adopted a fiscally prudent and conservative current year plan. Strengthening our balance sheet is our top priority at this time. We are focused on disciplined capital management, portfolio rationalization and cost saving measures.

  • For 2015, we are targeting debt reduction of $100 million through reduced capital spending, the suspension of our monthly dividend and selective asset dispositions. This will help to improve our financial flexibility in the near term.

  • In conjunction with the Company's reduced capital budget, we are targeting a 10 - 15% reduction in our general and administrative expense and a 5 - 10% reduction in our operating costs for the year (on a dollar basis). Including these cost savings, we estimate 2015 general and administrative expense will be approximately $2.50/Boe and operating costs will be approximately $13.50/Boe.

  • We expect that cash flows generated by additional disposition proceeds, our cost savings initiatives and any commodity price improvements will first be directed towards further debt reduction. Long Run's budget assumptions for 2015 are WTI US$52.50/Bbl, AECO $2.60/GJ and FX CDN/USD $0.80.

  • In the current commodity price environment, we continue to hedge our oil and natural gas production to protect the Company's funds flow from further downside price risk. For the first half of 2015, we have hedged approximately 70% of our oil production with an average price floor of WTI US$79.69/Bbl and 55% of our natural gas production with an average price floor of $3.46/GJ. Total hedged volumes for 2015 are now approximately 55% for both oil and natural gas.

  • Our disciplined approach to 2015 is designed to maximize longer term shareholder returns, while prioritizing balance sheet protection.

2015 OPERATIONS UPDATE

  • In managing our $100 million capital program, we are focused on achieving improved cost efficiencies. We continue to expect first half of 2015 development capital to be $50 million and we will revisit our plans for the second half of the year if commodity prices further deteriorate.

  • For the first half of 2015, we expect to drill 9 wells, including 5 in the Peace River Montney, 3 in the Pine Creek Cardium and 1 in the Kakwa Cardium.

  • At Peace River, Long Run has successfully drilled 5 Montney wells planned for the first half of 2015. All 5 wells have been completed and were placed on production by the end of February. Initial rates for these wells continue to meet our forecast expectations.

  • Long Run has successfully completed the first of a three well horizontal Cardium program at Pine Creek planned for the first quarter of 2015. The initial rates of the first Pine Creek well continue to exceed our forecast rates and have averaged greater than 1,000 Boe/d over the first two weeks of production. The second Cardium well of the Pine Creek program has been drilled and is expected to be completed in early March. Long Run is currently drilling the final Pine Creek Cardium well planned for the first half of the year.

  • At Kakwa, Long Run has drilled and completed one horizontal Cardium well, as described in our February 9, 2015 news release. Our successful drilling program has allowed us to fulfill our capacity commitment at the Musreau gas plant. We expect to continue our Cardium drilling program at Kakwa in the second half of 2015.

  • Current production of 36,000 Boe/d (41% liquids) is on target to meet our 2015 production guidance of 32,000 - 33,000 Boe/d (43% liquids).

ADVISORIES

Non-GAAP Measures

The press release contains terms commonly used in the oil and gas industry, such as funds flow from operations and net debt. These terms are not defined by International Financial Reporting Standards ("IFRS") and should not be considered an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with IFRS as an indicator of Long Run's performance. These measures are commonly used in the oil and gas industry and by Long Run to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. Long Run's determination of these measures may not be comparable to that reported by other companies. Funds flow from operations is calculated as cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. Net debt is calculated as bank debt plus working capital deficiency and principal amount of outstanding convertible debentures. Long Run has provided information on how these measures are calculated in the Management's Discussion and Analysis for the year ended December 31, 2014, which is available under the Company's SEDAR profile at www.sedar.com.

Barrels of Oil Equivalent

Barrels of oil equivalent may be misleading, particularly if used in isolation. A Boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Initial Production Rates

Initial production rates disclosed herein are not determinative of the rates at which the well will continue to produce and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery.

Netbacks

Netbacks are calculated by subtracting royalties, transportation costs and operating costs from revenue.

Reserve Life index

Reserve life index is calculated using the midpoint of Long Run's 2015 annual production guidance.

Forward Looking Statements

This press release contains forward-looking information within the meaning of applicable securities laws relating to the Company's plans and other aspects of Long Run's anticipated future operations, management focus, objectives, strategies and priorities including 2015 capital expenditure budget and nature of expenditures, 2015 forecast annual production, 2015 estimated operating and general and administrative costs, plans to strengthen Long Run's balance sheet and to reduce debt primarily through reduced capital spending, dispositions, and the suspension of Long Run's monthly dividend, the expectation that cash flows generated by additional disposition proceeds, cost savings initiatives and commodity price improvements will be first directed toward further debt reduction, hedging plans for 2015, the expectation that third party outages will be materially reduced with completion of facilities, plans to reduce first quarter 2015 capital expenditures as a result of increased expenditures in fourth quarter 2014 and plans to revisit capital spending plans in the second half of the year if commodity prices further deteriorate. Forward-looking information typically uses words such as "anticipate", "believe", "project", "expect", "goal", "plan", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future. The forward-looking information is based on certain key expectations and assumptions made by Long Run's management, including expectations and assumptions concerning commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs and general and administrative costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labor and services; the impact of increasing competition; ability to market oil and natural gas successfully; and Long Run's ability to access capital, and obtaining the necessary regulatory approvals; and Long Run's ability to dispose of assets to reduce debt.

Although the Company believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Long Run can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that the Company will derive there from. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide a more complete perspective on Long Run's future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

These forward-looking statements are made as of the date of this press release and Long Run disclaims any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

ABBREVIATIONS

Oil and Natural Gas Liquids Natural Gas
Bbl barrels Mcf thousand cubic feet
Bbl/d barrels per day Mcf/d thousand cubic feet per day
NGL natural gas liquids MMcf/d Million cubic feet per day
Boe barrels of oil equivalent
Boe/d barrels of oil equivalent per day
Liquids light oil, heavy oil, and NGLs
MBoe thousand barrels of oil equivalent

Contact Information

  • Long Run Exploration Ltd.
    William E. Andrew
    Chair and Chief Executive Officer
    (403) 261-6012

    Long Run Exploration Ltd.
    Corine Bushfield
    Senior Vice President and Chief Financial Officer
    (403) 261-6012

    Long Run Exploration Ltd.
    Lauren Kimak
    Investor Relations
    (403) 716-3222 / (888) 598-1330
    information@longrunexploration.com
    www.longrunexploration.com