Bonavista Energy Corporation

TSX : BNP


Bonavista Energy Corporation

February 27, 2014 21:30 ET

Bonavista Energy Corporation Announcing 2013 Fourth Quarter Results

CALGARY, ALBERTA--(Marketwired - Feb. 27, 2014) - Bonavista Energy Corporation (TSX:BNP) is pleased to report to shareholders its results for the fourth quarter ended December 31, 2013. Bonavista's Audited Consolidated Financial Statements and Notes, as well as Management's Discussion and Analysis for the years ended December 31, 2013 and 2012 are available on SEDAR at www.sedar.com or can be obtained from Bonavista's website at www.bonavistaenergy.com.

Highlights
Three months ended Years ended
December 31, % December 31, %
2013 2012 Change 2013 2012 Change
Financial
($ thousands, except per share)
Production revenues 245,466 223,021 10 % 964,312 832,491 16 %
Funds from operations(1) 124,354 110,015 13 % 477,578 378,667 26 %
Per share(1) (2) 0.62 0.57 9 % 2.42 2.16 12 %
Dividends declared(3) 38,904 63,481 (39 %) 152,968 224,801 (32 %)
Per share 0.21 0.36 (42 %) 0.84 1.44 (42 %)
Net income 6,667 14,442 (54 %) 49,505 64,202 (23 %)
Per share(4) 0.03 0.07 (57 %) 0.25 0.37 (32 %)
Adjusted net income(5) 23,702 16,535 43 % 75,297 58,049 30 %
Per share(4) 0.12 0.09 33 % 0.38 0.33 15 %
Total assets 4,235,626 4,062,852 4 %
Long-term debt, net of working capital 1,155,764 963,678 20 %
Long-term debt, net of adjusted working capital(6) 1,124,198 963,500 17 %
Shareholders' equity 2,270,015 2,285,889 (1 %)
Capital expenditures:
Exploration and development 111,596 76,937 45 % 443,829 402,090 10 %
Acquisitions, net of dispositions 4,815 118,837 (96 %) 20,530 (10,956 ) 287 %
Weighted average outstanding equivalent shares: (thousands)(4)
Basic 199,254 192,638 3 % 197,296 175,581 12 %
Diluted 201,756 194,322 4 % 199,340 176,747 13 %
Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 287 269 7 % 278 253 10 %
Natural gas liquids (bbls/day) 15,103 14,563 4 % 15,093 14,074 7 %
Oil (bbls/day)(7) 12,208 12,395 (2 %) 12,039 12,997 (7 %)
Total oil equivalent (boe/day) 75,072 71,842 4 % 73,406 69,250 6 %
Product prices:(8)
Natural gas ($/mcf) 3.54 3.22 10 % 3.35 2.60 29 %
Natural gas liquids ($/bbl) 49.35 42.60 16 % 47.61 45.19 5 %
Oil ($/bbl)(7) 72.73 75.73 (4 %) 79.32 77.30 3 %
Operating expenses ($/boe) 8.77 8.69 1 % 8.93 9.07 (2 %)
General and administrative expenses ($/boe) 1.21 1.22 (1 %) 1.15 1.10 5 %
Cash costs ($/boe)(9) 12.91 12.67 2 % 13.00 13.26 (2 %)
Operating netback ($/boe)(10) 20.82 19.12 9 % 20.54 17.70 16 %
Years ended December 31, %
Highlights (cont'd) 2013 2012 Change
Drilling (gross wells): 128 115 11 %
Natural gas 58 47 23 %
Oil 68 67 1 %
Average success rate 98 % 99 % (1 %)
Land:
Undeveloped (net acres) 1,281,191 1,253,141 2 %
Total (net acres) 2,891,947 2,832,701 2 %
Reserves: (11)
Proved:
Natural gas (bcf) 950.4 921.0 3 %
Oil and natural gas liquids (mbbls) 97,822 94,914 3 %
Total oil equivalent (mboe) 256,216 248,409 3 %
Proved plus probable:
Natural gas (bcf) 1,472.0 1,372.3 7 %
Oil and natural gas liquids (mbbls) 153,195 143,505 7 %
Total oil equivalent (mboe) 398,529 372,220 7 %
% Proved producing 39 % 40 % (1 %)
% Proved 64 % 67 % (3 %)
% Probable 36 % 33 % 3 %
Net present value of future cash flow before income taxes ($ millions):
0% discount rate 9,726 9,005 8 %
5% discount rate 6,310 5,742 10 %
10% discount rate 4,608 4,126 12 %
15% discount rate 3,608 3,183 13 %
Reserve life index (years): (12)
Total proved 9.1 9.6 (5 %)
Total proved plus probable 13.2 13.5 (2 %)
Reserves (boe per thousand shares - basic):
Total proved 1,282 1,283 -
Total proved plus probable 1,994 1,924 4 %
Finding and development expenditures - proved plus probable ($/boe):
Including changes in future development expenditures 11.95 14.66 (18 %)
Excluding changes in future development expenditures 11.56 11.23 3 %
Finding, development and acquisition expenditures - proved plus probable ($/boe):
Including changes in future development expenditures 11.03 11.16 (1 %)
Excluding changes in future development expenditures 8.75 6.98 25 %
Recycle ratio - proved plus probable: (13)
Including changes in future development expenditures 1.9 1.6 19 %
Excluding changes in future development expenditures 2.3 2.5 (8 %)

NOTES:

(1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented does 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 includes both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan (DRIP) and Bonavista's stock dividend program (SDP). For the three months ended December 31, 2013 approximately 1.2 million common shares were issued under the DRIP and SDP with an approximate value of $14.2 million. For the year ended December 31, 2013, approximately 4.6 million common shares were issued under the DRIP and SDP with an approximate value of $59.2 million.
(4) Basic net income per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
(5) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts.
(6) Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities.
(7) Oil includes light, medium and heavy oil.
(8) Product prices include realized gains and losses on financial instrument commodity contracts.
(9) Cash costs equal the total of operating, transportation, general and administrative, and financing expenses.
(10) Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe basis.
(11) Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista's royalty interests.
(12) Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by the independent reserve evaluator (GLJ).
(13) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition expenditures per boe.
Three months ended
Share Trading Statistics December 31,
2013
September 30,
2013
June 30,
2013
March 31,
2013
($ per share, except volume)
High 14.04 14.37 16.77 15.18
Low 11.25 12.70 13.33 12.25
Close 13.92 12.93 13.65 14.94
Average Daily Volume - Shares 1,000,966 620,864 428,813 676,012

MESSAGE TO SHAREHOLDERS

In 2013, Bonavista successfully executed on its commitment to maximize shareholder value demonstrated by a solid year of performance as we validated the quality of our asset base and the capabilities of our team. As a key component of our business plan, we demonstrated a 26% increase in our funds from operations over 2012, representing growth of 12% on a per share basis.

Improved natural gas prices and our focus on enhancing our operating and capital efficiencies were the primary sources for this increase in funds from operations. This was evidenced by steadily lowering our cost of adding production to approximately $21,000 per boe per day during the fourth quarter of 2013 from $32,500 per boe per day during the fourth quarter of 2012, on a trailing 12 month basis. Additionally, our ability to improve our finding and development costs by 18% to $11.95 per boe (including changes in future development expenditures) and our finding, development and acquisition costs to $11.03 per boe (including changes in future development expenditures) are a testament to this focus on efficiency gains. Lastly, we achieved a two percent improvement in operating and cash costs and when included with a seven percent increase in realized product prices, resulted in a year-over-year improvement in our recycle ratio to 1.9:1 from 1.6:1 in 2012.

These achievements were realized by focusing our attention in our West Central and Deep Basin core areas where we have the opportunity and expertise to drive enhancements in our performance and execution. Our strategy has led to an increased concentration of land, production and reserves in these multi-zone, prolific areas of the Western Canadian Sedimentary Basin. As a result, a group of non-core assets which cannot compete for investment within these core areas were rationalized for approximately $110.9 million as part of our concentration strategy.

Our business plan to maximize shareholder value is based upon a balanced approach of generating income and growth. In 2013, we experienced a six percent increase in our production volumes while our dividend program delivered an annualized yield of approximately six percent, collectively exceeding our total return goal. Our growth strategy is centered on achieving total returns in excess of 10% at fixed commodity prices of $3.50 per gj for natural gas at AECO and Cdn$95.00 per bbl WTI equivalent over the next five years. The continued success of this business plan will lie in our ability to remain focused on continued improvements in both operating and capital efficiencies and our ability to manage risk and safeguard our funds from operations through our hedging strategy.

The successful implementation of our business plan has led to multiple achievements during 2013, some of which are outlined below.

Operational and Financial Accomplishments for 2013 include:

  • Achieved a record average annual production rate of 73,406 boe per day, representing a 6% increase over last year and record quarterly production of 75,072 boe per day in the fourth quarter. Bonavista is currently producing approximately 74,000 boe per day, net of recent dispositions of approximately 2,500 boe per day in the first quarter of 2014 for proceeds of $103 million;
  • Improved our 2013 operating costs on a per boe basis by 2% to $8.93 per boe from $9.07 per boe as compared to 2012. Operating costs for the three months ended December 31, 2013 were $8.77 per boe;
  • Executed an effective capital expenditure program, investing $443.8 million in exploration and development activities drilling 128 wells with an overall success rate of 98%. In the fourth quarter, Bonavista spent approximately $111.6 million on exploration and development, drilling 27 wells with an overall success rate of 100%;
  • Production revenues were 16% higher at $964.3 million in 2013 when compared to 2012. For the fourth quarter, production revenues were $245.5 million representing a 10% increase from the fourth quarter of 2012;
  • Realized funds from operations of $477.6 million in 2013 representing a 26% increase from 2012. Funds from operations during the fourth quarter were $124.4 million, a 13% improvement from the same period in 2012;
  • Managed our exposure to commodity price fluctuations for 2014 resulting in approximately 66% of our forecasted net natural gas revenues hedged at an average floor price of $3.40 per gj at AECO and 70% of our net oil and liquids revenues hedged at an average floor price of Cdn$89.35 per bbl WTI. Additionally, in 2015 we have hedged approximately 50% of net natural gas revenues at an average floor price of $3.60 per gj at AECO and 30% of our net oil and liquids revenues at an average floor price of Cdn$90.00 per bbl WTI;
  • Delivered cumulative dividends of over $2.6 billion or $27.03 per common share since we introduced an income component to our shareholder return in July 2003; and
  • Elected to reduce the commitment amount under our bank credit facility to $600 million from $1.0 billion. The $400 million reduction in the commitment results in annual savings of approximately $1.7 million in standby fees or $0.06 per boe on our cash costs. With the reduction, we still have committed bank credit availability of approximately $367.8 million. The weighted average interest rate under the bank facility was 3.1% for the year ended December 31, 2013.

2013 Reserves Highlights

  • Replaced 2013 annual production by 198%, adding 53.1 mmboe of proved plus probable reserves, bringing total year end 2013 reserves to 398.5 mmboe representing a 7% increase over 2012 equivalent to a 4% per share increase;
  • Generated a solid reserve life index of 9.1 years on a proved basis and 13.2 years on a proved plus probable basis;
  • Reduced finding and development costs (excluding acquisitions and divestitures) by 18% to $11.95 per boe on a proved plus probable basis (including changes in future development capital), which reflects the improvement in capital efficiencies achieved in 2013 with our exploration and development program;
  • Achieved 2013 finding, development and acquisition costs, including changes in future development expenditures, of $14.60 per boe on a proved basis ($13.44 per boe excluding changes in future development expenditures) and $11.03 per boe on a proved plus probable basis ($8.75 per boe excluding changes in future development expenditures);
  • Three year average finding, development and acquisition costs, including changes in future development expenditures are $15.31 per boe on a proved basis ($10.93 per boe excluding changes in future development expenditures) and $12.07 per boe on a proved plus probable basis ($9.37 per boe excluding changes in future development expenditures);
  • Generated an attractive proved plus probable operating netback recycle ratio of 1.9:1 based on 2013 operating netbacks and 2.2:1 based on forecasted 2014 operating netbacks; and
  • Increased proved plus probable future development capital by 9% to $1.5 billion, representing the future growth and development potential in our asset portfolio. Future development capital as a ratio of forecasted 2014 capital expenditures and cash flow are 3.1:1 and 2.5:1 times respectively.

The reserves estimates contained in the following tables represent Bonavista's gross reserves as at December 31, 2013 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests.

A summary of this independent reserves evaluation is presented in the tables below:

Reserves:(1)(4) Natural Gas
(mmcf)
Light and
Medium Oil
(mbbls)
Heavy Oil
(mbbls)
Natural Gas
Liquids
(mbbls)
Total
Reserves(2)
(mboe)
Proved:
Proved producing 575,880 21,450 3,153 34,250 154,833
Proved non-producing 19,319 720 431 984 5,356
Proved undeveloped 355,169 4,914 266 31,652 96,028
Total proved 950,368 27,085 3,851 66,886 256,216
Probable 521,634 11,733 2,109 41,532 142,313
Total proved plus probable 1,472,002 38,818 5,959 108,418 398,529
Proved reserve life index (years)(3) 9.1
Proved plus probable reserve life index (years)(3) 13.2
(1) Bonavista's gross reserves are based on the GLJ reserve report dated February 20, 2014, GLJ reserve estimates based on forecast prices and costs as of January 1, 2014.
(2) Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(3) Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by GLJ.
(4) Amounts may not add due to rounding.

The following table highlights Bonavista's proved plus probable reserves, proved plus probable finding and development ("F&D") expenditures and proved plus probable finding, development and acquisition ("FD&A") expenditures and the associated recycle ratios:

2013 2012 2011
Proved plus probable reserves (mboe):(1)
Opening balance 372,220 341,390 310,749
Discoveries and extensions 41,946 36,645 33,667
Acquisitions and dispositions 14,655 20,266 22,402
Revisions and economic factors (3,537 ) (844 ) (365 )
Production (26,755 ) (25,236 ) (25,063 )
Closing balance 398,529 372,220 341,390
Operating netback ($/boe) (2) 20.54 17.70 24.53
Operating netback ($/boe) three-year average(2) 20.92 22.03 24.05
Finding and development expenditures:
Total F&D expenditures (excluding changes in future development expenditures) ($millions) 443.8 402.1 453.6
Proved plus probable F&D costs ($/boe)(3) 11.56 11.23 13.62
F&D recycle ratio(4) 1.8 1.6 1.8
Proved plus probable F&D three-year costs ($/boe)(3) 12.09 11.30 11.35
F&D recycle ratio three-year average(4) 1.7 1.9 2.1
Total F&D expenditures (including changes in future development expenditures) ($millions) 458.8 524.7 480.5
Proved plus probable F&D costs ($/boe)(3) 11.95 14.66 14.43
F&D recycle ratio(4) 1.7 1.2 1.7
Proved plus probable F&D three-year costs ($/boe)(3) 13.62 13.89 13.32
F&D recycle ratio three-year average(4) 1.5 1.6 1.8
Finding, development and acquisition expenditures:
Total FD&A expenditures (excluding changes in future development expenditures) ($millions) 464.4 391.1 617.1
Proved plus probable FD&A costs ($/boe) (3) 8.75 6.98 11.08
FD&A recycle ratio(4) 2.3 2.5 2.2
Proved plus probable FD&A three-year costs ($/boe)(3) 9.37 9.02 9.15
FD&A recycle ratio three-year average(4) 2.2 2.4 2.6
Total FD&A expenditures (including changes in future development expenditures) ($millions) 585.1 625.8 778.7
Proved plus probable FD&A costs ($/boe)(3) 11.03 11.16 13.98
FD&A recycle ratio(4) 1.9 1.6 1.8
Proved plus probable FD&A three-year costs ($/boe)(3) 12.07 12.82 12.86
FD&A recycle ratio three-year average(4) 1.7 1.7 1.9
(1) Amounts may not add due to rounding.
(2) Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs calculated on a per barrel of oil equivalent basis.
(3) Both F&D and FD&A costs take into account reserve revisions during the year on a per barrel of oil equivalent basis (6:1).
(4) Recycle ratio is defined as operating netback per barrel of oil equivalent divided by either F&D or FD&A costs on a per barrel of oil equivalent.

Future development costs of $1.5 billion at year end 2013 have the following development schedule:

Year Future Development Costs, Proved plus probable reserves, undiscounted ($ millions)
2014 319
2015 521
2016 289
2017 207
2018 109
Thereafter 49
Total 1,494

2013 Acquisition and Divestiture Highlights

  • Completed 30 property transactions in 2013, resulting in net expenditures of $20.5 million;
  • Completed acquisitions of $131.4 million adding production of 3,670 boe per day at closing and 2,430 boe per day on average for the year, and proved plus probable reserves of 20.5 mmboe;
  • Divested of $110.9 million of non-core assets comprising 1,290 boe per day of production at closing and 745 boe per day on average for the year and 5.8 mmboe of proved plus probable reserves; and
  • Closed a strategic acquisition during the fourth quarter in the Deep Basin area of $29 million, adding production of approximately 725 boe per day and over 26 Bluesky locations. Since closing, optimization and drilling investment of $9.7 million has resulted in production growing to approximately 2,100 boe per day.

2013 Core Area Highlights

West Central Alberta Core Area

Hoadley Glauconite Liquids Rich Natural Gas:

Bonavista drilled 12 horizontal Glauconite wells during the fourth quarter for a total of 42 wells in 2013. Our activity during the year was focused primarily on optimizing capital efficiencies. We achieved this through maximizing facility and infrastructure utilization while reducing the development cost of this substantial resource through initiatives like our extended reach horizontal well program. Based upon our first three extended reach horizontal wells, we experienced an average cost reduction of 13% per well when compared to the cost of equivalent reservoir access from two wells. As we refine this extended reach technology, we expect the use of this development technique to improve capital efficiencies throughout the entire Glauconite trend.

Our Glauconite horizontal well program in 2013 exceeded our expectations with average first month production rates of 500 boe per day. Production from the Hoadley Glauconite play in 2013 was 16,860 boe per day representing a 13% increase from the prior year. We have been successful with our cost structure achieving an overall reduction in costs of four percent when compared to 2012. Bonavista's Hoadley development program generates an internal rate of return of 50% and a recycle ratio of 3.8:1 at an AECO price of $3.50 per gj. These compelling economics rank it amongst the top natural gas plays in North America. Given these attractive economics, the predictability of well performance and our continued success in optimizing capital efficiencies, we have increased our 2014 activity by 57%, with plans to spend $141 million drilling approximately 66 wells. This level of development will result in a record year of activity for Bonavista within the Hoadley Glauconite trend.

To support this increase in activity, Bonavista has recently partnered with an area midstream operator, in the building of two 28 kilometer pipelines which will provide an incremental 130 mmcf per day of gathering capacity from the Hoadley Glauconite play to the Rimbey processing facility. The two pipelines include a 12 inch line to gather natural gas and a six inch line to gather natural gas liquids. This project is scheduled to be commissioned in the third quarter of 2014. Additionally, during the first quarter of 2015, we expect the commissioning of the Rimbey deep cut facility which will positively impact our economics as a result of increased natural gas liquids recoveries.

Bonavista continues to be an industry leader in the Hoadley Glauconite play having drilled a total of 186 horizontal wells since 2008. Our land acquisition program and down spacing initiatives have resulted in a current drilling inventory in excess of 400 horizontal locations. With more than 75% of the original natural gas in place remaining in the reservoir, a stable inventory contemplating four wells per section, and the predictability and repeatability of the reservoir, the Glauconite will remain the anchor development project for Bonavista in 2014.

Cardium Light Oil:

Bonavista drilled two horizontal Cardium wells in the fourth quarter bringing total 2013 activity to 27 wells. The 2013 program involved the development of emerging areas of our land base such as Lochend and Strachan to confirm our understanding of reservoir capabilities. Despite this commitment to emerging areas in 2013, our continued focus on improving capital efficiencies has resulted in cost reductions on average of approximately $200,000 per well when compared to 2012.

The Willesden Green area has been a focus area over the past 18 months. With numerous wells on production for a full year, we are confident in our completion approach of utilizing slick water fracture treatments to generate a 10 to 15% improvement in well performance. Our 2014 development plans involve drilling five wells and initiating a water flood pilot.

At Lochend, we drilled one well in the fourth quarter and seven wells in total for the year. Despite being constrained by facility limitations, initial well performance has been strong with first month production averaging over 300 boe per day. As a result of this well performance, we invested approximately $9 million in the construction of a 29 kilometer, eight inch pipeline from Lochend to a deep cut facility at Harmattan during the fourth quarter. This pipeline addition will not only add to our extensive operated infrastructure, it will create an unrestricted flow path for our current producing wells and will adequately accommodate our planned activity for 2014 at Lochend.

Our 2014 capital expenditure plan is primarily focused on development in Willesden Green and Lochend, totaling approximately $53 million and drilling 20 wells. We have remained prudently active in the Cardium over the past five years drilling a total of 113 horizontal wells to date, while maintaining a healthy inventory of horizontal locations, representing a profitable, multi-year development opportunity.

Ellerslie Liquids Rich Natural Gas:

During the fourth quarter, Bonavista drilled one horizontal Ellerslie oil well at Garrington, which had an initial 30-day rate of 350 boe per day, which includes 170 bbls per day of oil production. We expect this well to perform similar to our offset well that has demonstrated stable production performance at an average 190 bbls per day of oil over the first eight months. The significant presence of oil in the Ellerslie at Garrington creates an attractive netback of $40 per boe resulting in individual well payouts of approximately one year.

In the second half of 2013, we drilled our first liquids rich natural gas Ellerslie horizontal well at Westerose which has demonstrated an initial 90-day production rate of 840 boe per day. With a well cost of $2.7 million, the economic performance of this well has encouraged our investment in a three dimensional seismic program to determine the extent of the Ellerslie reservoir.

Similarly at Caroline, we drilled an Ellerslie liquids rich natural gas horizontal well in the second half of 2013. Despite having many operational challenges with the well, we successfully completed four stages (originally designed for 12) resulting in a stable rate of 525 boe per day over its first five months of production.

We are exceedingly pleased with our development results in the Ellerslie formation throughout 2013. Hence, our 2014 plan contemplates a drilling program of 12 wells with an associated budget of approximately $44 million, representing a two-fold increase in activity over 2013. We will focus on the opportunities with lower operational risk at Garrington and Westerose where we anticipate an increase in execution success. As we become more intimate with the reservoir, we anticipate well performance that continues to meet or exceed our expectations. With a meaningful oil and natural gas liquids yields of approximately 100 bbls per mmcf on average, economic performance will continue to strengthen as we refine our operational approach. As an active operator in the Ellerslie over the past decade, our strategy had been to continue to strengthen our land position as we delineated the resource opportunity with vertical well development. Over the past 24 months we have acquired valuable horizontal operational experience in the play which has enhanced and accelerated the value of this play within our organization. Since 2010, we have grown our inventory of horizontal locations in excess of 200 locations and have assembled an extensive land base of 135 prospective sections. With netbacks currently averaging $30 per boe and decline rates approximating 50% in the first year of production, our 2013 activity has certainly exceeded our economic expectations. Consequently, we see the Ellerslie becoming a cornerstone of our development program in the near future.

Deep Basin Core Area

Bonavista had an active drilling program in the fourth quarter participating in 10 horizontal wells bringing our total 2013 drilling activity to 21 horizontal wells in our Deep Basin core area. We have been tremendously pleased with the overall results and look forward to continued success.

Current production in the Deep Basin core area is approximately 16,500 boe per day and has grown 22% from a year ago. Our capital plan for 2014 involves spending $102 million, drilling 29 wells and infrastructure spending of $34 million.

Our expansion in this core area is expected to result in capital efficiency improvements as larger drilling programs take place. Over the past four years, we have assembled a position of approximately 238,000 net acres with over 200 future horizontal locations. Bonavista currently operates natural gas processing capacity of approximately 230 mmcf per day and we continue to invest in additional infrastructure in 2014. We see the Deep Basin core area providing both near-term and mid-term growth especially as we transition from the building phase to commercial development with many of our plays. We remain committed to our Deep Basin area and are confident about its growth profile.

Wilrich Natural Gas:

We have experienced tremendous success with the Wilrich formation in 2013. Building on an important asset acquisition of 5,000 boe per day of production and 79,000 net acres of land in 2012, we exited 2013 acquiring access to an additional 26,000 acres of land and have added 2,800 boe per day of production through our exploration and development program.

The majority of this land acquisition throughout 2013 has taken place in the Ansell area of the Deep Basin. Early in 2013, we gained access to 20,000 acres of Wilrich land at Ansell and have since drilled and completed two horizontal wells on this acreage. The results of these two wells have exceeded our expectations at restricted 90-day production rates averaging 900 boe per day per well. The first well has been on production for 10 months and has cumulatively produced 1.2 bcf of raw natural gas in that period of time. Currently, with access to over 44 sections of land at Ansell and the potential of multiple prospective zones, we have planned an $84 million capital budget for this area for 2014. We have committed to drilling 12 wells, five of which will be drilled in the first quarter of 2014. The first two have been drilled and completed using one drilling pad and have resulted in a combined rate of 34 mmcf per day after a 50 hour flow test. We have also committed to an infrastructure project in the first quarter of 2014, consisting of a 10 inch, 100 mmcf per day pipeline and a 30 mmcf per day compressor station. The pipeline and compressor station are expected to be commissioned by April 2014. The economic performance of our Wilrich play in Ansell is compelling at a natural gas price of $3.50 per gj at AECO. Single-well economics portray a recycle ratio of 3.5:1 with a 10 month payout. The impact of a stronger natural gas price, coupled with the success of our 2013 drilling program speaks well to the future development of this play.

At Marlboro, Bonavista holds approximately 28,000 net acres of Wilrich land. Our 2013 drilling program involved six gross horizontal wells (4.8 net) drilled into the Wilrich formation with these wells currently producing at a combined rate of 1,700 boe per day. The Wilrich at Marlboro provides Bonavista with an additional 35 horizontal drilling locations. Although the natural gas from the Wilrich formation at Marlboro tends to have less associated natural gas liquids, economics remain robust due to the prolific production performance with payouts under two years and rates of return in excess of 35% at a natural gas price of $3.50 per gj at AECO.

Bluesky Liquids Rich Natural Gas:

In the fourth quarter, Bonavista participated in five horizontal Bluesky wells consisting of two operated and three non-operated, totaling nine wells for 2013. Our latest Pine Creek horizontal well drilled in the fourth quarter is our highest rate Bluesky result to date, producing at an average 30-day raw natural gas rate of 8.6 mmcf per day and 35 bbls per mmcf of liquids, of which 50% is condensate. We remained active during the fourth quarter by adding to our Bluesky position in Pine Creek with the acquisition of approximately 725 boe per day of Bluesky production and access to approximately 12,000 net acres of Bluesky rights where we have identified an additional 25 horizontal locations. On a rate of return perspective, the individual well economics of the Bluesky are the best of our liquids rich natural gas plays.

Additional Emerging Opportunities

The Blueberry Montney play remains an important part of our long-term development plans. Industry activity in the Montney formation remains strong on all fronts with recent industry acquisition metrics of approximately $4,000 per acre, solidifying our interpretation of the value of our land base. Through focused efforts on efficiencies, we reduced our drilling, completion and tie-in costs to $6.3 million representing a 25% reduction from the average of the previous wells drilled into the formation. As our industry remains focused on exporting Canadian natural gas from the west coast, the Blueberry Montney field will continue to play an important role as a potential supply, as it is uniquely positioned to participate in LNG export economics. Meanwhile, Bonavista will continue to improve its understanding of the technology required to optimize the recovery of the Montney liquids rich resource at our Blueberry field. As such, we have planned to drill two wells in Blueberry during 2014.

In addition, Bonavista drilled and completed a Falher horizontal well in the West Central Alberta core area during the third quarter which has resulted in an initial 90-day production rate of approximately 600 boe per day including 60 bbls per mmcf of natural gas liquids. With the success of this well, we plan on additional reservoir delineation by drilling five horizontal wells in 2014.

Strengths of Bonavista Energy Corporation

Throughout our 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, and since January 2011 as a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless volatility and uncertainly inherent in a commodity business like the energy sector. We have consistently improved the quality of our projects and have maintained a high level of investment activity on our asset base. This has resulted in an increase in corporate production by approximately 110% since converting to an energy trust in July 2003 and a further 10% since converting back to a corporation three years ago. These results stem from the expertise of our people and their entrepreneurial approach to consistently generating profitable development projects in an unpredictable commodity price environment within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid understanding of our assets as they exercise the discipline and commitment required to deliver long-term value to our shareholders. We actively participate in undeveloped land purchases, producing property acquisitions and farm-in opportunities, which have all enhanced the quality of our extensive drilling inventory. These activities have led to low cost reserve additions and a predictable production base that continues to grow at a steady pace. Our production is currently approximately 65% natural gas weighted and is geographically focused in multi-zone regions primarily in Alberta. The predictable production performance and low cost structure of our asset base ensures favourable operating netbacks in most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over the pace of operations and direct influence over our operating and capital cost efficiencies.

Our team brings a successful track record of executing low to medium risk development programs, while incorporating acquisitions and sound 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 consisting of disciplined cost controls and prudent financial management. Directors, management and employees also own approximately 13% of the equity of Bonavista, aligning our interests with external shareholders.

Outlook

With the recent strengthening in natural gas prices due to cold weather across much of North America, we remain cautiously optimistic as we move into 2014. We do however remain aware of the robust natural gas production capability on this continent. This capability has been powered by prolific resource discoveries, associated natural gas production from oil and liquids drilling and continued improvements in the techniques used to exploit these resources. Given this backdrop, Bonavista will maintain a disciplined approach to commodity hedging and continue to take advantage of the recent increases in natural gas prices to secure future funds from operations. Operationally, we will continue to focus on being one of the most efficient producers within our peer group and continue to pursue low cost, repeatable opportunities throughout our concentrated portfolio of assets. These strategies coupled with our on-going asset concentration program will support our commitment to maximize shareholder returns through a balance of income and growth.

To support this strategy and in light of the successful first quarter dispositions, Bonavista has a budgeted capital program of between $460 and $500 million in 2014. This includes spending between $560 and $600 million on exploration and development activities, offset by approximately $100 million of dispositions and does not contemplate further acquisitions at this time. The exploration and development program is expected to result in approximately 150 wells drilled and an average daily production forecast for the year of between 76,000 and 78,000 boe per day. Using the mid-point of our production estimate, Bonavista will deliver approximately five percent production growth in 2014 in spite of the non-core dispositions. With current commodity prices and hedges in place, we expect to exit 2014 with a debt to funds from operations ratio of approximately 1.8:1 and an all in payout ratio of 106%.

Bonavista wishes to announce that Mr. Harry Knutson is retiring from the Board of Directors of the Company effective today. Mr. Knutson has served on the Board of Directors since 1997 and has provided valuable guidance, expertise and oversight since then. We would like to thank him for his 17 years of service to Bonavista and wish him all the best in the future.

Bonavista previously announced the addition of Ms. Sue Lee as a member of the Board of Directors in November 2013 and is currently conducting a search for an additional director, which we expect to communicate at our next annual general meeting in May.

We thank our employees and directors for their commitment and dedication to our strategy throughout the year and our shareholders for their trust and support. We firmly believe that we have the right people and assets required to execute our five year strategy with efficiency and precision. Our employees are the foundation of our continued success.

On behalf of the Board of Directors

Keith A. MacPhail Jason E. Skehar
Executive Chairman President and Chief Executive Officer
February 27, 2014
Calgary, Alberta
BONAVISTA ENERGY CORPORATION
Supplemental Financial Information
Consolidated Statements of Financial Position
December 31, December 31,
(thousands) 2013 2012
(unaudited)
Assets:
Current assets:
Accounts receivable $ 124,431 $ 102,500
Prepaid expenses 7,322 11,089
Marketable securities 2,645 2,768
Other assets 13,786 12,191
Financial instrument commodity contracts 419 8,608
148,603 137,156
Financial instrument commodity contracts 346 1,224
Financial instrument contracts 8,023 4,293
Property, plant and equipment 3,845,344 3,691,572
Exploration and evaluation assets 222,085 217,382
Goodwill 11,225 11,225
$ 4,235,626 $ 4,062,852
Liabilities and Shareholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 213,118 $ 181,674
Decommissioning liabilities 9,313 -
Dividends payable 13,087 21,303
Financial instrument commodity contracts 31,985 8,786
267,503 211,763
Financial instrument commodity contracts 3,710 1,550
Long-term debt 1,046,177 889,071
Other long-term liabilities 13,853 13,650
Decommissioning liabilities 397,174 447,753
Deferred income taxes 237,194 213,176
Shareholders' equity:
Shareholders' capital 2,228,210 2,059,305
Exchangeable shares 307,468 405,183
Contributed surplus 61,247 44,848
Deficit (326,910 ) (223,447 )
2,270,015 2,285,889
$ 4,235,626 $ 4,062,852
BONAVISTA ENERGY CORPORATION
Supplemental Financial Information
Consolidated Statements of Income and Comprehensive Income
Three months ended
December 31,
Years ended
December 31,

(thousands, except per share amounts)
2013 2012 2013 2012
(unaudited)
Revenues:
Production $ 245,466 $ 223,021 $ 964,312 $ 832,491
Royalties (30,099 ) (29,650 ) (124,489 ) (124,300 )
215,367 193,371 839,823 708,191
Realized gains (losses) on financial instrument commodity contracts (1,769 ) 204 (13,652 ) 8,581
Unrealized gains (losses) on financial instrument commodity contracts (22,742 ) (2,793 ) (34,426 ) 8,210
(24,511 ) (2,589 ) (48,078 ) 16,791
190,856 190,782 791,745 724,982
Expenses:
Operating 60,601 57,464 239,196 229,847
Transportation 9,206 9,732 36,595 38,367
General and administrative 8,361 8,049 30,802 27,927
Share-based compensation 5,777 5,845 23,868 19,450
Gain on disposition of property, plant and equipment (28,760 ) (21,449 ) (38,115 ) (59,675 )
Loss (gain) on disposition of exploration and evaluation assets (19 ) 311 (18,143 ) 5,938
Depletion, depreciation and amortization 90,844 90,282 349,285 331,023
146,010 150,234 623,488 592,877
Income from operating activities 44,846 40,548 168,257 132,105
Finance costs 20,439 9,493 98,439 53,350
Finance income 16,525 8,791 (3,730 ) (11,739 )
Net finance costs 36,964 18,284 94,709 41,611
Income before taxes 7,882 22,264 73,548 90,494
Deferred income taxes 1,215 7,822 24,043 26,292
Net income and comprehensive income $ 6,667 $ 14,442 $ 49,505 $ 64,202
Net income per share - basic $ 0.03 $ 0.07 $ 0.25 $ 0.37
Net income per share - diluted $ 0.03 $ 0.07 $ 0.25 $ 0.36
BONAVISTA ENERGY CORPORATION
Supplemental Financial Information
Consolidated Statements of Changes in Equity
For the years ended December 31
(thousands) Shareholders'
capital
Exchangeable
shares
Contributed
surplus
Deficit Total
shareholders'
equity
(unaudited)
Balance as at December 31, 2012 $ 2,059,305 $ 405,183 $ 44,848 $ (223,447 ) $ 2,285,889
Net income - - - 49,505 49,505
Issue costs, net of future tax benefit (74 ) - - - (74 )
Issued for cash on exercise of common share incentive rights 1,984 - - - 1,984
Exercise of common share incentive rights 2,708 - (2,708 ) - -
Conversion of restricted share awards 7,410 - (7,410 ) - -
Share-based compensation expense - - 23,868 - 23,868
Share-based compensation capitalized - - 2,649 - 2,649
Issued pursuant to the dividend reinvestment and stock dividend plans 59,162 - - - 59,162
Exchangeable shares exchanged for common shares 97,715 (97,715 ) - - -
Dividends declared - - - (152,968 ) (152,968 )
Balance as at December 31, 2013 $ 2,228,210 $ 307,468 $ 61,247 $ (326,910 ) $ 2,270,015
Balance as at December 31, 2011 $ 1,446,804 $ 585,754 $ 32,092 $ (62,848 ) $ 2,001,802
Net income - - - 64,202 64,202
Issuance of equity, net of issue costs 334,736 - - - 334,736
Issued for cash on exercise of common share incentive rights 4,510 - - - 4,510
Exercise of common share incentive rights 4,609 - (4,609 ) - -
Conversion of restricted share awards 5,183 - (5,183 ) - -
Share-based compensation expense - - 20,070 - 20,070
Share-based compensation capitalized - - 2,478 - 2,478
Issued pursuant to the dividend reinvestment and stock dividend plans 82,892 - - - 82,892
Exchangeable shares exchanged for common shares 180,571 (180,571 ) - - -
Dividends declared - - - (224,801 ) (224,801 )
Balance as at December 31, 2012 $ 2,059,305 $ 405,183 $ 44,848 $ (223,447 ) $ 2,285,889
BONAVISTA ENERGY CORPORATION
Supplemental Financial Information
Consolidated Statements of Cash Flows
Three months ended Years ended
December 31, December 31,
(thousands) 2013 2012 2013 2012
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 6,667 $ 14,442 $ 49,505 $ 64,202
Adjustments for:
Depletion, depreciation and amortization 90,844 90,282 349,285 331,023
Share-based compensation 5,777 7,017 23,868 18,364
Unrealized (gains) losses on financial instrument commodity contracts 22,742 2,793 34,426 (8,210 )
Gain on disposition of property, plant and equipment (28,760 ) (21,449 ) (38,115 ) (59,675 )
Loss (gain) on disposition of exploration and evaluation assets (19 ) 311 (18,143 ) 5,938
Net finance costs 36,964 18,284 94,709 41,611
Deferred income taxes 1,215 7,822 24,043 26,292
Decommissioning expenditures (10,539 ) (11,410 ) (30,143 ) (25,530 )
Changes in non-cash working capital items (9,870 ) (5,206 ) (2,830 ) 13,466
115,021 102,886 486,605 407,481
Financing Activities:
Issuance of senior notes (49 ) - 229,226 -
Issuance of equity, net of issue costs - - (99 ) 331,188
Proceeds on exercise of common share incentive rights 228 355 1,984 4,510
Dividends paid (24,480 ) (38,323 ) (102,022 ) (137,898 )
Interest paid (19,369 ) (14,892 ) (40,793 ) (40,907 )
Proceeds from long-term debt 44,057 - 119,791 -
Repayment of long-term debt - 127,198 (235,970 ) (182,329 )
387 74,338 (27,883 ) (25,436 )
Investing Activities:
Business acquisitions (29,795 ) (155,266 ) (102,284 ) (155,266 )
Exploration and development (111,596 ) (76,937 ) (443,829 ) (402,090 )
Property and other business acquisitions (2,435 ) (9,491 ) (16,275 ) (14,626 )
Property dispositions 27,415 45,920 98,029 180,848
Office equipment (2,066 ) (704 ) (6,183 ) (3,307 )
Changes in non-cash working capital items 3,069 19,254 11,820 12,396
(115,408 ) (177,224 ) (458,722 ) (382,045 )
Change in cash - - - -
Cash, beginning of period - - - -
Cash, end of period $ - $ - $ - $ -

FORWARD-LOOKING INFORMATION

Forward-Looking Statements - Certain information set forth in this document, including management's assessment of Bonavista's future plans and operations, contains forward-looking statements including; (i) forecasted capital expenditures and plans; (ii) exploration, drilling and development plans, (iii) prospects and drilling inventory and locations; (iv) anticipated production rates; (v) anticipated operating and service costs; (vi) our financial strength; (vii) incremental development opportunities; (viii) reserve life index; (ix) total shareholder return; (x) growth prospects; (xi) asset acquisition and disposition plans; (xii) sources of funding, which are provided to allow investors to better understand our business. By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond Bonavista's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonavista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that Bonavista will derive there from. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Non-IFRS Measurements - Within this press release, references are made to terms commonly used in the oil and natural gas industry. Management uses "funds from operations" and the "ratio of debt to funds from operations" to analyze operating performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculation 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. Basic funds from operations per share is calculated based on the weighted average number of common shares outstanding in accordance with International Financial Reporting Standards. Operating netbacks equal production revenue and realized gains or losses on financial instrument commodity contracts, less royalties, transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Management uses these terms to analyze operating performance and leverage.

Conversion of Natural Gas to Barrels of Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Contact Information

  • Bonavista Energy Corporation
    Keith A. MacPhail
    Executive Chairman
    (403) 213-4300

    Jason E. Skehar
    President & CEO
    (403) 213-4300

    Glenn A. Hamilton
    Senior Vice President & CFO
    (403) 213-4300
    www.bonavistaenergy.com