Bellatrix Exploration Ltd. Announces First Quarter 2014 Financial Results

May 6, 2014 12:05 AM

CALGARY, May 6, 2014 /CNW/ – Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) (TSX, NYSE MKT: BXE) announces its financial and operating results for the three months ended March 31, 2014.

Forward-Looking Statements

This press release, including the report to shareholders, contains forward-looking statements. Please refer to our cautionary language on forward-looking statements and the other matters set forth at the beginning of the management’s discussion and analysis (the “MD&A”) attached to this press release.

HIGHLIGHTS


		Three months ended March 31,
		2014	2013
FINANCIAL (unaudited)
(CDN$000s except share and per share amounts)
Revenue (before royalties and risk management ⁽¹⁾)		163,585	65,543
Funds flow from operations ⁽²⁾		77,642	37,545
	Per basic share ⁽⁵⁾	$0.45	$0.35
	Per diluted share ⁽⁵⁾	$0.45	$0.32
Cash flow from operating activities		84,300	35,527
	Per basic share ⁽⁵⁾	$0.49	$0.33
	Per diluted share ⁽⁵⁾	$0.48	$0.30
Net profit		25,167	4,561
	Per basic share ⁽⁵⁾	$0.15	$0.04
	Per diluted share ⁽⁵⁾	$0.14	$0.04
Exploration and development		152,686	91,459
Corporate		2,956	140
Property acquisitions		260	10
Capital expenditures – cash		155,902	91,609
Property dispositions – cash		(39)	5
Corporate acquisitions and other non-cash items		–	787
Total capital expenditures – net ⁽⁴⁾		155,863	92,401
Long-term debt		335,118	150,827
Convertible debentures ⁽⁶⁾		–	51,105
Adjusted working capital (excess) deficiency ⁽³⁾		137,970	43,488
Total net debt ⁽³⁾		473,088	245,420
Total assets		1,707,929	759,775
Total shareholders’ equity		933,670	386,750

OPERATING			Three months ended March 31,
			2014	2013
Average daily sales volumes
	Crude oil, condensate and NGLs	(bbls/d)	12,405	5,983
	Natural gas	(mcf/d)	135,865	80,158
	Total oil equivalent	(boe/d)	35,049	19,343
Average prices
	Light crude oil and condensate	($/bbl)	98.65	92.11
	NGLs (excluding condensate)	($/bbl)	57.50	42.30
	Heavy oil	($/bbl)	62.77	53.69
	Crude oil, condensate and NGLs	($/bbl)	80.41	73.60
	Crude oil, condensate and NGLs (including risk management ⁽¹⁾)	($/bbl)	74.67	73.44
	Natural gas	($/mcf)	5.88	3.50
	Natural gas (including risk management⁽¹⁾)	($/mcf)	4.88	4.42
	Total oil equivalent	($/boe)	51.27	37.28
	Total oil equivalent (including risk management⁽¹⁾)	($/boe)	45.36	41.02

Statistics
	Operating netback ⁽⁴⁾	($/boe)	32.86	21.03
	Operating netback ⁽⁴⁾ (including risk management⁽¹⁾)	($/boe)	26.95	24.77
	Transportation	($/boe)	1.61	0.83
	Production expenses	($/boe)	8.12	8.65
	General & administrative	($/boe)	1.75	2.06
	Royalties as a % of sales after transportation		17%	19%

COMMON SHARES
Common shares outstanding			172,761,228	107,919,329
Share options outstanding			9,472,505	9,293,228
Shares issuable on conversion of convertible debentures ⁽⁶⁾			–	9,821,429
Fully diluted common shares outstanding			182,233,733	127,033,986
Diluted weighted average shares – net profit ⁽⁵⁾			174,321,930	110,725,084
Diluted weighted average shares – funds flow from operations and cash flow from operating activities ^{(2) (5)}			174,321,930	120,546,513
SHARE TRADING STATISTICS
TSX and Other ⁽⁷⁾
(CDN$, except volumes) based on intra-day trading
High			9.44	6.70
Low			7.64	4.03
Close			9.35	6.54
Average daily volume			1,848,581	674,726
NYSE MKT
(US$, except volumes) based on intra-day trading
High			8.55	6.60
Low			6.93	4.10
Close			8.43	6.43
Average daily volume			156,011	67,190

⁽¹⁾	The Company has entered into various commodity price risk management contracts which are considered to be economic hedges. Per unit metrics after risk management include only the realized portion of gains or losses on commodity contracts.

	The Company does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per unit metrics calculations disclosed.

⁽²⁾	The highlights section contains the term “funds flow from operations” which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with generally accepted accounting principles (“GAAP”) as an indicator of the Company’s performance. Therefore reference to the non-GAAP measures of funds flow from operations, or funds flow from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in the MD&A. Funds flow from operations per share is calculated using the weighted average number of common shares for the year.

⁽³⁾	Net debt and total net debt are considered non-GAAP measures. Therefore reference to the non-GAAP measures of net debt or total net debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2014 calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Net debt and total net debt include the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is a non-GAAP measure calculated as net working capital deficiency (excess) excluding short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. For the comparative 2013 calculation, net debt also excludes the liability component of convertible debentures which were then outstanding. A reconciliation between total liabilities under GAAP and total net debt and net debt as calculated by the Company is found in the MD&A.

⁽⁴⁾	Operating netbacks and total capital expenditures – net are considered non-GAAP measures. Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures – net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.

⁽⁵⁾	Basic weighted average shares for the three months ended March 31, 2014 were 171,626,707 (2013: 107,882,027).

	In computing weighted average diluted earnings per share for the three months ended March 31, 2014, a total of 2,695,223 (2013: 2,843,057) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and a total of nil (2013: 9,821,429) common shares issuable on conversion of convertible debentures were added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 174,321,930 (2013: 110,725,084).

	In computing weighted average diluted cash flow from operating activities and funds flow from operations per share for the three months ended March 31, 2014, a total of 2,695,223 (2013: 2,843,057) common shares were added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options and no common shares issuable (2013: 9,821,429) on conversion of convertible debentures were added to the denominator as they were dilutive, resulting in diluted weighted average common shares of 174,321,930 (2013: 120,546,513). As a consequence, no interest and accretion expense (net of income tax effect) was added to the numerator (2013: $0.8 million).

⁽⁶⁾	During the year ended December 31, 2013, the Company announced a notice of redemption of its then outstanding $55.0 million 4.75% convertible debentures, with a redemption date set of October 21, 2013. During September and October 2013, the $55.0 million principal amount of remaining convertible debentures were converted or redeemed in exchange for an aggregate of 9,794,848 common shares of the Company. For the three months ended March 31, 2013, shares issuable on conversion of convertible debentures were calculated by dividing the $55.0 million principal amount of the convertible debentures by the conversion price of $5.60 per share.

⁽⁷⁾	TSX and Other includes the trading statistics for the Toronto Stock Exchange and other Canadian trading markets.

REPORT TO SHAREHOLDERS

Bellatrix posted a record quarter highlighted by:

Q1 2014 earnings of $25 million ($0.15 per basic share) up 452% over Q1 2013
Q1 2014 funds flow from operations of $78 million ($0.45 per basic share) up 107% over Q1 2013
Q1 2014 production of 35,049 boe/d (35% Oil & NGL’s) up 81% over Q1 2013
Revenues of $164 million up 150% over Q1 2013
Capital expenditures of $156 million
100% success in drilling and/or participating in 44 gross / 25.6 net wells
Q1 2014 operating costs of $7.53/boe after deducting processing and third party income
General and administration (“G&A”) expenses reduced to $1.75/boe compared to $2.06/boe in Q1 2013

During the first quarter of 2014 Bellatrix faced significant production constraints at third party midstream gas processing facilities. In the Strachan, Ferrier, Brazeau and Pembina areas of West Central Alberta the existing gas processing capacity has been overwhelmed by industry’s accelerated development of resources, primarily in the Cardium and Mannville formations, effectuated by the successful adaptation of horizontal drilling techniques coupled with innovative application of slick water fracturing technology.

In an effort to alleviate the impacted midstream gas processing issues, Bellatrix has been very proactive. Early in 2013, the Company completed a front end engineering design, an environmental assessment and obtained the necessary regulatory approvals to construct a new Bellatrix deep cut gas plant in the Alder Flats area of West Central Alberta. Phase One of the facility will process 110 mmcf/d of raw gas and is designed to extract 99% of the propane, and 100% of the butane and condensate from the inlet raw gas stream. Construction is underway with an anticipated commissioning date of July 1, 2015. Phase Two is expected to be commissioned by April 1, 2016 doubling the inlet raw gas processing capacity to 220 mmcf/d. The facility will significantly reduce operating costs while doubling current liquid recovery from the gas stream. An additional $70 million of capital, relating to the deep cut plants, will be spent in the second half of 2014 for a revised net capital budget of $440 million for fiscal 2014. Bellatrix plans to utilize funds from operations and existing credit facilities to fund ongoing capital spending and operating requirements.

In addition, the Company has negotiated a firm service agreement to process 100 mmcf/d at the Blaze Gas Plant located in West Pembina (4-31-48-12W5M) yielding a significant reduction in processing fees. The reduced operating costs coupled with increased liquid recoveries provided by the Blaze Facility further insulates the Company against commodity price fluctuations while improving long term profitability.

On April 2, 2014, Bellatrix announced the completion of a 1.6 km river bore and a 7 km pipeline in conjunction with Blaze Energy Ltd. (“Blaze”), completing a 55 km pipeline to tie-in Bellatrix natural gas for processing in the Blaze gas plant. The pipeline was commissioned on April 1, 2014 at 11:00 am reaching 35 mmcf/d in the first day of operation. During the month of April, Blaze incrementally increased Bellatrix’s gas volumes as they recommissioned the facility to handle processing the higher volumes delivered by Bellatrix. As of May 1, 2014 the plant was accepting up to 90 mmcf/d at the inlet of the facility.

In the fourth quarter of 2013 and in the first quarter of 2014, Bellatrix installed a total of 8 field booster compressors located at 13-5-45-9W5 (tie-in point to the Blaze pipeline) with capacity of 97 mmcf/d. As the pipeline ramped up to full capacity and current constraints are removed, Bellatrix expects that the previously announced production restrictions in West Central Alberta will be alleviated. Current production levels the first week of May are +/- 40,000 boe/d.

Also during the Q1 2014 the Company invested in the following facilities:

Installed 75 km of 3″ to 6″ gathering lines
Commenced construction of phase two of the Ferrier 9-3 compressor station increasing compression from 6,700 HP to 13,400 HP
Commenced construction of North Brazeau 5-5 Oil Battery
Completed an 8 inch lateral line from South Brazeau to the Ferrier 13-5 compressor facility
Initiated build out of a high capacity Baptiste gathering system designed for 50 mmcf/d

Grafton Joint Venture Capital Investment Increase

On April 10, 2014, Bellatrix announced that Grafton Energy Co. I Ltd. (“Grafton”) elected to exercise an option to increase committed capital investment to the Grafton Joint Venture established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as the previously announced Grafton Joint Venture. Grafton’s increased capital investment will continue to support the accelerated development of a portion of Bellatrix’s extensive undeveloped land holdings.

The Grafton Joint Venture is located in the Willesden Green and Brazeau areas of West-Central Alberta. Under the terms of the amended agreement prior to the exercise of this option, Grafton was committed to contributing 82%, or$200 million, to the $244 million Joint Venture to participate in an expected 58 net Notikewin/Falher and Cardium well program. Under the agreement, Grafton will earn 54% of Bellatrix’s working interest (“WI”) in each well drilled in the development program until payout (being recovery of Grafton’s capital investment plus an 8% return) on the total program, reverting to 33% of Bellatrix’s WI after payout. At any time after payout of the entire program, Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty on Bellatrix’s pre-Joint Venture WI. The effective date of the initial agreement for the Joint Venture is July 1, 2013 and had an initial term of 2 years. With the exercise of the $50 million option, Bellatrix shall have until the end of the third anniversary of the effective date to spend the additional capital.

Operational highlights for the three months ended March 31, 2014 include:

Bellatrix posted a 100% success rate during the first quarter of 2014, drilling and/or participating in 44 gross (25.56 net) wells, resulting in 36 gross (21.87 net) Cardium oil wells, 7 gross (3.04 net) Notikewin/Falher liquids-rich gas wells, and one gross (0.65 net) Cardium gas well.
Q1 2014 sales volumes averaged 35,049 boe/d (weighted 35% to oil, condensate, and NGLs, and 65% to natural gas). This represents an 81% increase over average sales volumes in the first quarter of 2013 of 19,343 boe/d and a 61% increase over average sales in the fourth quarter of 2013 of 21,829 boe/d.
During the first quarter of 2014, the Company spent $155.9 million on capital projects, compared to $91.6 million in Q1 2013.
As at March 31, 2014, Bellatrix had approximately 409,074 net undeveloped acres of land in Alberta, British Columbiaand Saskatchewan.

Financial highlights for the three months ended March 31, 2014 include:

The net profit for Q1 2014 was $25.2 million ($0.15 per basic share), compared to $4.6 million in Q1 2013.
Q1 2014 revenue before royalties and risk management contracts was $163.6 million, 150% higher than the $65.5 million recorded in Q1 2013. The increase in revenues in the first quarter of 2014 was primarily due to significantly increased light oil and condensate, NGL, and natural gas sales volumes in conjunction with higher realized prices for all commodities, partially offset by reduced heavy oil sales volumes compared to Q1 2013.
Funds flow from operations for the first quarter of 2014 was $77.6 million ($0.45 per basic share), an increase of 107% from $37.5 million ($0.35 per basic share) in Q1 2013. The increase in funds flow from operations between the 2014 and 2013 periods was principally due to increased overall production volumes and higher realized prices for all commodities, partially offset by a higher net realized loss on commodity contracts, increased general and administrative expenses, operating, transportation, and royalties expenses.
Crude oil, condensate and NGLs produced 56% of petroleum and natural gas sales revenue for the three months ended March 31, 2014.
Production expenses for Q1 2014 were $8.12/boe ($25.6 million), compared to $8.65/boe ($15.1 million) in the first quarter of 2013. The decrease in production expenses per boe was primarily due to increased production volumes resulting from 2013 and Q1 2014 drilling in areas with lower production expenses, as well as continued field optimization projects. Production expenses, after deducting processing and other third party income, for the three months ended March 31, 2014 were $7.53/boe ($23.8 million), compared to $8.28/boe ($14.5 million) in Q1 2013.
Operating netbacks after including risk management for Q1 2014 were $26.95/boe, up from $24.77/boe in Q1 2013. Operating netbacks before risk management for Q1 2014 were $32.86/boe, up from $21.03/boe in the first quarter of 2013. The increased netbacks including risk management were primarily the result of higher realized prices for all commodities and lower production expenses, partially offset by a realized loss on commodity contracts in Q1 2014 compared to a net gain in Q1 2013, higher transportation expenses, and increased royalty expenses.
G&A expenses for Q1 2014 decreased on a per boe basis to $1.75/boe ($5.5 million), compared to $2.06/boe ($3.6 million) for Q1 2013.
As at March 31, 2014, Bellatrix had $164.9 million undrawn on its total $500 million credit facility.
Total net debt as of March 31, 2014 was $473.1 million.

As of May 5, 2014, the Company has entered into commodity price risk management arrangements as follows:


Type	Period	Volume	Price Floor	Price Ceiling	Index
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	500 bbl/d	$ 93.30 US	$ 93.30 US	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	1,500 bbl/d	$ 94.00 CDN	$ 94.00 CDN	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	500 bbl/d	$ 95.00 US	$ 95.00 US	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	1,500 bbl/d	$ 95.22 CDN	$ 95.22 CDN	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	500 bbl/d	$ 98.30 CDN	$ 98.30 CDN	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	1,000 bbl/d	$ 99.50 CDN	$ 99.50 CDN	WTI
Crude oil fixed	January 1, 2014 to Dec. 31, 2014	500 bbl/d	$ 99.60 CDN	$ 99.60 CDN	WTI
Natural gas fixed	April 1, 2013 to June 30, 2014	15,000 GJ/d	$ 3.05 CDN	$ 3.05 CDN	AECO
Natural gas fixed	January 1, 2014 to Dec. 31, 2014	20,000 GJ/d	$ 3.30 CDN	$ 3.30 CDN	AECO
Natural gas fixed	January 1, 2014 to Dec. 31, 2014	20,000 GJ/d	$ 3.60 CDN	$ 3.60 CDN	AECO
Natural gas fixed	July 1, 2014 to Dec. 31, 2014	15,000 GJ/d	$ 3.71 CDN	$ 3.71 CDN	AECO
Natural gas fixed	February 1, 2014 to Dec. 31, 2014	10,000 GJ/d	$ 3.79 CDN	$ 3.79 CDN	AECO
Natural gas fixed	February 1, 2014 to Dec. 31, 2014	10,000 GJ/d	$ 3.80 CDN	$ 3.80 CDN	AECO
Natural gas fixed	February 1, 2014 to Dec. 31, 2014	15,000 GJ/d	$ 3.85 CDN	$ 3.85 CDN	AECO
Natural gas fixed	February 1, 2014 to Dec. 31, 2014	10,000 GJ/d	$ 3.84 CDN	$ 3.84 CDN	AECO
Natural gas fixed	March 1, 2014 to Dec. 31, 2014	10,000 GJ/d	$ 4.14 CDN	$ 4.14 CDN	AECO

OUTLOOK

With the major infrastructure constraints behind us, Bellatrix will once again turn its full attention to growth and increasing shareholder value.

During the second quarter the Company will utilize its existing multi-well drilling and production pad sites to maintain at least 5 active drilling rigs targeting 20 to 22 gross (9 to 10 net) wells. As soon as practical, when existing road restrictions are removed, Bellatrix will be active in drilling with 10 to 12 rigs operating in its two core resource plays, the Cardium oil (Bellatrix is the second largest land holder with 338 net sections in the Cardium play) and Mannvillecondensate rich gas, utilizing horizontal drilling multi-fracturing technology for the remainder of 2014. A revised net capital budget of $440 million has been set for fiscal 2014. Based on the timing of proposed expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the 2014 budget is anticipated to provide 2014 average daily production of approximately 42,500 boe/d to 43,500 boe/d and an exit rate of approximately 47,000 boe/d.

Raymond G. Smith, P. Eng.
President and CEO
May 5, 2014

Note:

Bellatrix’s annual and special meeting of shareholders is scheduled for 3:00 pm on May 21, 2014 in the Devonian Room at the Calgary Petroleum Club.

The Company’s current corporate presentation is available at www.bellatrixexploration.com.

Bellatrix Exploration Ltd. Announces First Quarter 2014 Financial Results

Latest Headlines