Long Run Explor Ltd Ord WFREF

Q4 & end of year report

[northwestcoast]

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).