Bonavista Energy Corp BNPUF

Energy Oil & Gas E&P

GREY:BNPUF - Post by User

Bonavista Energy Corp

Bullboard Posts

Post by Al42on Feb 25, 2016 6:54pm

348 Views

Post# 24596524

Another 70% slash to the dividend!!

Press release from Marketwire

Bonavista Energy Corporation Announces 2015 Fourth Quarter and Year End Results, Reduced Capital Spending and Dividend for 2016

Thursday, February 25, 2016

Bonavista Energy Corporation Announces 2015 Fourth Quarter and Year End Results, Reduced Capital Spending and Dividend for 2016

18:41 EST Thursday, February 25, 2016

CALGARY, ALBERTA--(Marketwired - Feb. 25, 2016) - Bonavista Energy Corporation ("Bonavista") (TSX:BNP) is pleased to report to shareholders its financial and operating results for the fourth quarter and year ended December 31, 2015. Highlights include the reduction in fourth quarter operating costs by 21% to $5.85 per boe, decreased cash costs to $9.80 per boe and a 33% improvement in finding and development costs to $7.26 per boe, supporting Bonavista's emphasis on cost reductions and efficiency improvements. Bonavista's Audited Consolidated Financial Statements and Notes, as well as Bonavista's Management's Discussion and Analysis ("MD&A") for the years ended December 31, 2015 and 2014, are available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com and on Bonavista's website at www.bonavistaenergy.com.


Highlights
			Three months ended December 31,						Years ended December 31
			2015		2014		% Change		2015		2014		% Change
Financial
($ thousands, except per share)
Production revenues			137,260		244,612		(44	)%	599,999		1,106,852		(46	)%
Funds from operations⁽¹⁾			95,792		135,845		(29	)%	385,351		561,105		(31	)%
	Per share^{(1) (2)}		0.44		0.63		(30	)%	1.77		2.69		(34	)%
Dividends declared⁽³⁾			11,664		42,754		(73	)%	76,762		164,750		(53	)%
	Per share		0.06		0.21		(71	)%	0.37		0.84		(56	)%
Net income (loss)			(454,616	)	(60,978	)	(646	)%	(751,545	)	4,847		(15,605	)%
	Per share⁽⁴⁾		(2.09	)	(0.28	)	(646	)%	(3.45	)	0.02		(17,350	)%
Adjusted net loss⁽⁵⁾			(443,793	)	(199,730	)	(122	)%	(696,634	)	(136,643	)	(410	)%
	Per share⁽⁴⁾		(2.04	)	(0.93	)	(119	)%	(3.20	)	(0.65	)	(392	)%
Total assets									3,523,716		4,429,402		(20	)%
Long-term debt, net of working capital									1,265,820		1,032,029		23	%
Long-term debt, net of adjusted working capital⁽⁶⁾									1,310,663		1,155,422		13	%
Shareholders' equity									1,548,266		2,357,706		(34	)%
Capital expenditures:
	Exploration and development		56,084		162,155		(65	)%	313,905		639,560		(51	)%
	Dispositions, net of acquisitions		(5,540	)	(87,868	)	(94	)%	(30,552	)	(106,777	)	(71	)%
Weighted average outstanding equivalent shares: (thousands)⁽⁴⁾
	Basic		218,010		215,855		1	%	217,660		208,719		4	%
	Diluted		220,924		218,571		1	%	220,117		210,957		4	%
Operating
(boe conversion - 6:1 basis)
Production:
	Natural gas (mmcf/day)		325		359		(9	)%	337		314		7	%
	Natural gas liquids (bbls/day)		20,804		18,256		14	%	17,666		15,991		10	%
	Oil (bbls/day)⁽⁷⁾		4,934		7,688		(36	)%	5,445		8,873		(39	)%
		Total oil equivalent (boe/day)	79,862		85,810		(7	)%	79,288		77,211		3	%
Product prices:⁽⁸⁾
	Natural gas ($/mcf)		3.44		3.87		(11	)%	3.56		4.27		(17	)%
	Natural gas liquids ($/bbl)		19.39		37.56		(48	)%	23.17		49.78		(53	)%
	Oil ($/bbl)⁽⁷⁾		86.61		83.76		3	%	81.23		80.72		1	%
Operating expenses ($/boe)			5.85		7.38		(21	)%	6.60		8.25		(20	)%
General and administrative expenses ($/boe)			0.97		1.02		(5	)%	1.12		1.14		(2	)%
Cash costs ($/boe)⁽⁹⁾			9.80		10.99		(11	)%	10.70		12.20		(12	)%
Operating netback ($/boe)⁽¹⁰⁾			15.76		19.63		(20	)%	16.16		22.60		(28	)%


Highlights
Year ended December 31			2015		2014		% Change
Drilling:
	Gross		78		134		(42	)%
	Net		70.1		111.6		(37	)%
Land (net acres):
	Undeveloped		705,610		816,085		(14	)%
	Total		1,929,041		2,218,776		(13	)%
Reserves:⁽¹¹⁾
Proved producing:
	Natural gas (bcf)⁽¹²⁾		614.9		662.0		(7	)%
	Oil and natural gas liquids (mbbls)⁽¹³⁾		59,592		59,129		1	%
	Total oil equivalent (mboe)		162,072		169,456		(4	)%
Total proved:
	Natural gas (bcf)⁽¹²⁾		1,026.0		1,094.4		(6	)%
	Oil and natural gas liquids (mbbls)⁽¹³⁾		91,230		93,329		(2	)%
	Total oil equivalent (mboe)		262,224		275,729		(5	)%
Proved plus probable:
	Natural gas (bcf)⁽¹²⁾		1,601.7		1,689.9		(5	)%
	Oil and natural gas liquids (mbbls)⁽¹³⁾		139,543		145,119		(4	)%
	Total oil equivalent (mboe)		406,494		426,768		(5	)%
		% Proved producing	40	%	40	%	-	%
		% Proved	65	%	65	%	-	%
		% Probable	35	%	35	%	-	%
Net present value of future cash flow before income taxes ($ millions, proved plus probable):
	0% discount rate		5,568		8,845		(37	)%
	5% discount rate		3,492		5,402		(35	)%
	10% discount rate		2,412		3,733		(35	)%
	15% discount rate		1,788		2,783		(36	)%
Reserve life index (years):⁽¹⁴⁾
	Total proved		9.7		9.4		3	%
	Proved plus probable		14.1		13.1		8	%
Reserves (boe per thousand shares - basic):
	Total proved		1,200		1,277		(6	)%
	Proved plus probable		1,860		1,977		(6	)%
Finding and development costs - proved plus probable ($/boe)⁽¹⁵⁾			7.26		10.86		(33	)%
Recycle ratio - proved plus probable⁽¹⁶⁾			2.2		2.1		5	%
Finding, development and acquisition costs - proved plus probable ($/boe)⁽¹⁵⁾			9.84		9.95		(1	)%
Recycle ratio - proved plus probable⁽¹⁶⁾			1.6		2.3		(30	)%

NOTES:
⁽¹⁾	Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented do not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.
⁽²⁾	Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
⁽³⁾	Dividends declared include both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan ("DRIP") and Bonavista's stock dividend program ("SDP"). There were no common shares issued under the DRIP and SDP for the three months ended December 31, 2015 and for the three months ended December 31, 2014. For the year ended December 31, 2015 there were no common shares issued under the DRIP and SDP, 1.7 million common shares were issued under the DRIP and SDP in the comparative year ended December 31, 2014.
⁽⁴⁾	Per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
⁽⁵⁾	Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts, net of tax
⁽⁶⁾	Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities.
⁽⁷⁾	Oil includes light, medium and heavy oil.
⁽⁸⁾	Product prices include realized gains and losses on financial instrument commodity contracts.
⁽⁹⁾	Cash costs equal the total of operating, transportation, general and administrative, and financing expenses.
⁽¹⁰⁾	Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe basis.
⁽¹¹⁾	Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista's royalty interests.
⁽¹²⁾	Includes Conventional Natural Gas, Shale Natural Gas and Coal Bed Methane.
⁽¹³⁾	Includes Natural Gas Liquids; and Light, Medium, Heavy and Tight Oil.
⁽¹⁴⁾	Calculated based on the amount for the relevant reserve category divided by the production forecast prepared by the independent reserve evaluator (GLJ).
⁽¹⁵⁾	Includes changes in future development costs.
⁽¹⁶⁾	Recycle ratio is calculated using operating netback per boe divided by either finding and development or finding, development and acquisition costs per boe.


Share Trading Statistics	Three months ended
Share Trading Statistics	December 31, 2015	September 30, 2015	June 30, 2015	March 31, 2015
($ per share, except volume)
High	4.25	6.80	9.26	8.15
Low	1.60	2.93	6.35	5.62
Close	1.82	3.07	6.79	6.38
Average Daily Volume - Shares	1,210,201	1,047,494	1,050,652	763,522

MESSAGE TO SHAREHOLDERS

Our operational and financial results in 2015 mark another milestone in our goal to re-establish Bonavista as a top decile producer in western Canada. Our cost structure is mirroring that of a decade ago, and our commitment to do more with less has resulted in modest growth in our 2015 production with capital spending less than half of that spent in 2014. This capital program consumed approximately 75% of our funds from operations in 2015 and when added to our dividend commitment, created a sustainable business plan with a total payout ratio of 94%.

Significant improvements in operating and capital efficiencies were realized for the third straight year. Operating costs per boe improved to $6.60 in 2015, a 20% improvement over last year, in addition, fourth quarter operating costs were $5.85 per boe, 21% improvement from the same period in 2014. Our proved and probable finding and development costs declined by 33% to $7.26 per boe when compared to 2014, generating a recycle ratio of 2.2:1. Lastly, our cost to add production from our exploration and development ("E&D") program in 2015 was reduced by approximately ten percent over 2014 and currently, we are adding production between $12,000 and $14,000 per boe per day.

A year ago, with the WTI oil price dropping below US$50.00 per bbl, and propane losing its monetary value, we committed to a total payout ratio being less than forecasted funds from operations for 2015. We delivered on that promise and are committed to that same approach in 2016, given the continued weakness in commodity prices.

Over the past 12 months, both spot natural gas and oil prices have decreased a further 30% to 40%, meaningfully impacting the economics of our key plays. However, strength in the forward curve beyond 2016 enhances those economics with the timing of capital expenditures being key to higher returns. This commodity price environment is also placing further downward pressure on service costs through reductions in capital budgets, while creating acquisition opportunities that are competing favourably with our E&D program. To be successful in the current economic environment, we will remain flexible with our 2016 capital program spending between $145 million and $190 million. We will target the lower end of this range as our base E&D budget, but will be prepared to increase spending on E&D activities should commodity prices strengthen. This flexibility will allow us to reinforce our financial position and/or take advantage of acquisition opportunities that compete favourably with our key play economics. This budget is expected to result in production between 69,000 and 73,000 boe per day. In addition, effective April 1, 2016, our Board of Directors has approved a 67% reduction in the dividend to $0.01 per share per quarter. Using the base E&D budget of $145 million our total payout ratio for 2016 will be approximately 70%, with the remaining funds, approximately $70 million, being applied to our long-term debt.

Operational and financial accomplishments for 2015 include:

Decreased fourth quarter operating costs by 21% to $5.85 per boe, and annual operating costs by 20% to $6.60 per boe;
Reduced F&D costs by 33% to $7.26 per boe on a proved plus probable basis, including changes in future development costs ("FDC"), resulting in a recycle ratio of 2.2:1;
Replaced 91% of production with proved developed producing reserve additions, while spending only 75% of our funds from operations, despite the loss of 10.3 mmboe resulting from the price-related acceleration of economics cutoffs;
Executed a capital spending program, including acquisitions and divestitures ("A&D") of $283.4 million, a 47% reduction relative to 2014. Exploration and development ("E&D") activities totaled $313.9 million, drilling 78 (70.1 net) wells as compared to $639.6 million in E&D activities drilling 134 (111.6 net) wells in 2014. Dispositions, net of acquisitions were approximately $30.6 million in 2015;
Generated funds from operations of $95.8 million ($0.44 per share) in the fourth quarter of 2015, a period where realized commodity prices decreased by 23% on a per boe basis and overall production revenues decreased by 44% respectively, when compared to the fourth quarter of 2014;
Produced 79,862 boe per day in the fourth quarter and 79,288 boe per day in 2015 resulting in three percent growth relative to 2014, notwithstanding a 47% reduction in capital spending;
Removed 14% of our inactive wells and 20% of our abandoned but unreclaimed wells year-over-year;
Extended our existing bank credit facility of $600 million to a maturity date of September 10, 2019; and
Enhanced our commodity hedges resulting in a current portfolio of:
- Approximately 228,500 gjs per day of natural gas hedged at an average floor price of $3.16 per gj at AECO for 2016 and approximately 121,822 gjs per day at an average floor price of $3.09 per gj for 2017;
- Approximately 2,700 bbls per day of oil hedged at an average floor price of CDN$78.95 per bbl WTI for 2016 and approximately 250 bbls per day at an average floor price of CDN$90.47 per bbl WTI for 2017; and
- 1,875 bbls per day of propane hedged at 46% of US WTI pricing for 2016 and 1,000 bbls per day at 40% of US WTI pricing for the first quarter of 2017.
- Using the midpoint of our production guidance for 2016, Bonavista has approximately 64% of volumes hedged and approximately 23,000 boe per day hedged for 2017.

2015 Acquisition and divestiture highlights:

Completed 19 property transactions resulting in divestments, net of acquisitions, of approximately 2,200 boe per day of non-core high cost assets. The disposed assets had operating costs in excess of $15.00 per boe.

2015 FOURTH QUARTER AND ANNUAL CORE AREA HIGHLIGHTS

WEST CENTRAL CORE AREA

Our West Central core area draws its strength from a low capital cost structure, resilient economics and consistent results. In 2015, we continued to enhance our execution improving our cost structure in the Glauconite and achieved excellent results from our Morningside drilling program. With over 900,000 net acres and approximately 800 drilling locations in our key plays, our West Central core area represents both reliable, low risk drilling opportunities and promising new key plays. We have built an extensive network of infrastructure including 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista, to support our continued development of this core area.

In 2015, our E&D spending in this core area was $175.5 million, drilling 56 (48.2 net) wells resulting in production of approximately 48,300 boe per day. This stable production rate was achieved while spending only 77% of our operating income for 2015, demonstrating the sustainability of our West Central development program.

Our Glauconite play has been the foundation of this sustainability, while the future potential of our Falher play continues to impress.

Glauconite Natural Gas

We drilled 46 (38.2 net) horizontal wells in 2015 including four (4.0 net) in the fourth quarter resulting in fourth quarter production of approximately 26,200 boe per day.

Our capital costs have improved throughout the year, with the cost to drill and complete a "typical" Glauconite well improving by 25% to $2.3 million when compared to 2014, while operating costs have decreased to below $4.50 per boe in our Hoadley area. Reduced costs and enhanced execution has resulted in annual production addition costs of approximately $12,300 per boe per day, a 10% improvement relative to 2014. The continued strength of the Glauconite play was also demonstrated by the 2015 proved plus probable finding and development costs coming in at a record low $3.74 per boe.

We continue to evolve our completion techniques from nitrogen foam to slick water fracs at Hoadley, resulting in improved well performance. Slick water, when combined with longer reach horizontal wells, has outperformed our conventional type curve by 200% after 12 months of production performance. This is accomplished at a cost equal to approximately 165% of our conventional Glauconite horizontal well.

In 2015, the commissioning of the deep cut processing facility at Rimbey resulted in a potential 30 bbl per mmcf increase in natural gas liquids from the Glauconite play (mostly ethane and propane). Unfortunately though, the challenging price environment for natural gas liquids has resulted in the curtailment of 20% to 60% of our ethane production. Furthermore, with negative propane pricing, we have chosen to redirect some Glauconite production to a Bonavista operated process facility. The benefits of natural gas with higher heat content and a lower operating cost structure at this facility will result in incremental operating income despite the lower recovery rates and production rates realized utilizing this process.

The Glauconite play continues to showcase consistent results with resilient economics that rank amongst the top liquids rich natural gas plays in North America. Our inventory of approximately 370 locations allows for over 13 years of development at our current pace. Our 2016 program entails drilling 16 to 30 (14.2 to 25.5 net) wells.

Spirit River Falher Natural Gas

We drilled eight (8.0 net) Falher wells in 2015 including one (1.0 net) in the fourth quarter.

Our 2015 Morningside Falher program has exceeded our expectations. We drilled six (6.0 net) wells at Morningside and successfully extended the boundaries of the play to the south of our main development area. Our six wells drilled in 2015 demonstrated average production rates of approximately 700 boe per day in their first three months.

Our Morningside Falher play continues to compete equally for capital with our Hoadley Glauconite and Ansell Wilrich plays. With current costs to drill and complete of $2.0 million, annual production addition costs remain less than $8,000 per boe with IRR's in excess of 25% at current commodity prices.

Our 2016 Falher program includes drilling between seven to nine (6.5 to 8.5 net) wells.

DEEP BASIN CORE AREA

In 2015, we continued to expand our foot-print in this liquids-rich natural gas core area. We have established a net land position of approximately 295,000 acres and have increased our inventory through swap and acquisition transactions. We currently have over 300 horizontal drilling locations of which approximately 30% are extended reach. We built additional infrastructure in 2015 by installing a processing facility and a metering station, resulting in further operating cost reductions and incremental egress.

In 2015, we spent $114.8 million on E&D activities drilling 21 (20.9 net) wells. Production has averaged approximately 21,500 boe per day representing a 24% increase from the same period last year despite drilling 34% fewer wells.

Spirit River Wilrich Natural Gas

We drilled 18 (18.0 net) Wilrich wells in 2015 including four (4.0 net) in the fourth quarter, which were our first extended reach (approximately 1.5 mile lateral length) wells.

Improvements to our cost structure have made a significant impact to our economics at Ansell. The commissioning of our new processing facility and metering station in the second half of 2015 will result in operating costs below $3.00 per boe.

The average cost to drill and complete our fourth quarter Ansell wells was $4.9 million, representing an improvement of approximately 14% from the prior year period, despite two of these wells being extended reach horizontal wells. Our annual cost to add production at Ansell is currently $11,000 per boe per day, a 25% reduction from the same period in 2014.

During the second half of 2015, we continued expanding our Wilrich inventory at Ansell through a strategic land swap which added approximately 45 locations, the majority being extended reach wells.

Our 2016 program contemplates drilling between nine and 13 extended reach horizontal wells. We anticipate further economic enhancements driven by improved capital and operating efficiencies as we develop our extended reach program.

STRENGTHS OF BONAVISTA ENERGY CORPORATION

Throughout our nineteen year history, from an initial restructuring in 1997 to create a high growth junior exploration company, through the energy trust phase between July 2003 and December 2010, to a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless commodity price volatility and uncertainty inherent in the energy sector. We have consistently maintained a high level of profitable investment activity on our asset base. This activity stems from the expertise of our people and their entrepreneurial approach to design profitable development projects with resilience to an unpredictable commodity price environment. Our experienced technical teams have a thorough understanding of our assets and the reservoirs within the Western Canadian Sedimentary Basin as they exercise the discipline and commitment required to deliver long-term value to our shareholders. The core operating and financial principles that guide our people have been with our organization from the beginning and remain solidly intact today.

As a result of our recent successful non-core disposition strategy, our production and development activity is now largely concentrated in two core areas in central Alberta. We create opportunity through undeveloped land purchases, asset swaps, acquisitions and farm-in opportunities in these areas. Specifically over the past five years, technology coupled with North American natural gas supply/demand fundamentals has led to numerous opportunities to reposition the asset portfolio and drastically improve the quality of our development projects. These activities have led to low cost reserve additions and a reliable production base. Today, the predictable production performance and optimized cost structure of our high quality asset base ensures operating netbacks that compete favorably in most operating environments. Furthermore, our assets are predominantly operated by us, providing control over the pace of operations and a direct influence over our operating and capital cost efficiencies.

Our team brings a successful track record of executing reliable development programs with consistency and precision. We continually strive for balance sheet flexibility and remain focused on prudent financial management. Our Board of Directors and management team possess extensive experience in the oil and natural gas business. They have successfully guided our organization through many different economic cycles utilizing a proven strategy underpinned with a set of consistent and reliable operating and financial principles. Directors, management and employees also own approximately 10% of the equity of Bonavista, aligning our interests with those of external shareholders.

Bullboard Posts

AI companies to invest in