NuVista Energy Ltd. Announces Fourth Quarter and Year End 2014 Operating Results, Reserves and Resources

CALGARY, ALBERTA--(Marketwired - March 8, 2015) - NuVista Energy Ltd. ("NuVista") (or the "Company") (TSX:NVA) is pleased to announce results for the three and twelve months ended December 31, 2014 and provide an update on its future business plans. NuVista had an exceptional year in 2014 on many fronts by:

  • Increasing natural gas and condensate production, reserves and contingent resources;
  • Successfully commencing operations of our new Bilbo compressor station on time and on budget;
  • Bringing on production 17 new Wapiti Montney wells for a total of 33;
  • Improving the performance of our Wapiti wells versus typecurve;
  • Further reducing total well costs per metre of rock accessed;
  • Materially increasing the volumes and prices associated with our commodity hedging program;
  • Continuing our rolling annual non-core divestiture program;
  • Continuing our successful delineation drilling and expiry management program; and
  • Significantly improving corporate netbacks while prudently managing our balance sheet.

These factors have placed NuVista in a position to weather the current low price environment with patience and strength without impairing our ability to grow rapidly and profitably in a healthy long term commodity price environment. In 2015, NuVista is prepared to use our flexibility to limit capital spending for prudent balance sheet management, and in turn retain the ability to accelerate capital spending should the commodity price environment improve as expected.

NuVista is pleased to announce a significant increase in our reserves and contingent resources as a result of the 2014 year end independent reserves and resources evaluation by GLJ Petroleum Consultants Ltd ("GLJ") (the "GLJ Report"). The Wapiti Montney play continues to exceed expectations as our flagship play with line-of-sight to exceptional organic production, reserves, and value growth for shareholders.

Significant Reserves Highlights for the year ending December 31, 2014:

  • Increased proved plus probable reserves ("TP+PA") by 58% to 220 MMBoe and total proved reserves ("TP") by 38% to 111 MMBoe as compared to year end 2013, despite divestitures of non-core assets through the year. Excluding the effect of these divestitures, the TP+PA and TP reserve increases were 72% and 54% respectively;
  • Increased condensate reserves versus the prior year by 80% on a TP+PA basis to 44.7 MMBoe. Condensate volumes now represent 20% of total TP+PA reserves, up from 18% in 2013;
  • Achieved 2014 corporate finding and development ("F&D") costs of $10.55/Boe on a TP+PA basis, including changes in future development costs ("FDC");
  • Improved the Company's recycle ratio to 1.6x on a TP+PA basis as compared to 1.0 in 2013 as the transformation to a Montney-focused company continued successfully;
  • Increased Montney TP+PA operating recycle ratio to 2.8x with full year Montney operating netbacks of $29.80/Boe;
  • Achieved positive technical reserves revisions on both a TP and TP+PA basis due to continued outperformance of producing wells;
  • Replaced 1,590% of production in the year on a TP+PA basis, while proved developed producing reserve additions alone replaced 250% of annual production;
  • Increased our reserve life index (1) ("RLI") on a TP+PA basis from 20.8 years to 25.9 years and increased the RLI on a TP basis from 12.0 years to 13.1 years as compared to year end 2013;
  • Increased our best estimate of Economic Contingent Resources ("ECR") by 23% to 3.13 Tcfe, from 2.55 Tcfe at the close of 2013. In addition TP+PA reserves increased by 0.58 Tcfe; and
  • Increased the total inventory of undrilled locations for TP+PA reserves to 194 wells and for ECR to 710 wells for a total of 904.

The ECR evaluation only includes approximately 65% of the NuVista holdings in the Wapiti Middle Montney, and does not yet include any of the Lower Montney zone. It is expected that significant value remains to be unlocked as NuVista continues to delineate its landholdings, and as resources are converted to reserves and production.

(1) RLI was calculated by dividing 2014 year end reserves by the midpoint of 2015 production guidance.

Significant Operating Highlights for the quarter and year ending December 31, 2014:

  • Achieved and exceeded the top end of our annual and fourth quarter guidance ranges, respectively. For the fourth quarter of 2014, NuVista's average production was 23,165 Boe/d compared to average production of 18,034 Boe/d for the fourth quarter of 2013 and 18,030 Boe/d for the third quarter of 2014. The increase in production of 28% from the fourth quarter of 2013 is due to strong performance of new and existing Wapiti Montney wells. This growth rate was partially offset by the sale of non core properties in 2014;
  • Achieved funds from operations of $36.7 million ($0.26/share, basic) for the three months ended December 31, 2014, a 70% increase from $21.5 million ($0.17/share, basic) for the three months ended December 31, 2013 due to increased production volumes more than offsetting weaker pricing, and the increased contribution of higher netback Wapiti Montney volumes. For the year ended December 31, 2014, NuVista's funds from operations were $110 million ($0.81/share, basic), a 46% increase from $75.3 million ($0.63/share, basic) in the same period of 2013 due to increased production volumes and commodity prices;
  • Successfully executed an annual capital program of $312 million. Drilled 21 (19.7 net) wells in our Montney condensate rich resource play while constructing and commencing production in our Bilbo block compressor station and trunk lines;
  • Entered into significant new firm processing contracts, strategically providing our Wapiti Montney play with capacity to grow to at least 2017 with flexibility, and guaranteed downstream liquids and natural gas transportation and fractionation;
  • Completed the disposition of certain non-core assets producing approximately 2,065 Boe/d for net proceeds of $81.6 million; and
  • Exited 2014 with bank borrowings of $172 million on a current facility of $300 million. Net debt, including the working capital deficiency was $184 million and net debt to annualized fourth quarter funds from operations was 1.3x;
  • Achieved several new IP30 Montney well results as shown in the table below:

New Well IP30 Results

Well Raw Gas Liquid Hydrocarbons Total Sales CGR
C5+/Raw
(MMcf/d) (Bbls/d) (Boe/d) (Bbls/MMcf)
Average Bilbo Montney development typecurve 5.8 435
Condensate
1,356 75
Well 30 (Bilbo Development) Location: 15-34-65-6 W6M 7.8 752
Condensate
1,978 97
Well 31 (Bilbo Development) Location: 16-34-65-6 W6M 8.8 663
Condensate
2,007 75
Well 32 (Bilbo Development) Location: 02/16-34-65-6 W6M 4.4 467
Condensate
1,158 107
Average Wapiti Montney delineation well typecurve 5.8 261
Condensate
1,217 45
Well 33 (South Delineation) Location: 1-28-66-6 W6M 2.9 481
Condensate
881 167

As evidenced by the strong well results, significant progress has been made in optimizing well completion technology for ever-improving results versus our typecurve. Progress on reducing well costs per metre of rock accessed has continued positively as we transition to two and three well pads as opposed to single well locations which dominated our drilling in 2011-2013. We anticipate costs to continue falling as the unit costs of supplies and services moves downward commensurate with the commodity price environment. Cost reductions in all aspects of our business remains a key area of focus for NuVista.

In 2014, NuVista announced significant progress in signing flexible firm processing arrangements for future growth with two tranches of raw gas processing contracts for capacity of 30 MMcf/d each, with startup anticipated in midyear of 2015 and 2016 respectively. We commenced construction in the fourth quarter of 2014 on the new Elmworth compressor station with an anticipated startup date of mid 2015. The station has an ultimate raw natural gas design capacity of 80 MMcf/d which will be added in modular stages as needed to serve the announced processing contracts plus potential future contracts.

2015 Guidance

In response to the recent downturn in commodity pricing NuVista announced in early 2015 that we had elected to revise our 2015 capital budget to a range of $270 to $290 million, which is reduced and high-graded from the original capital budget of $340 to $380 million announced in November of 2014. Spending for the first half of 2015 will be approximately 50 to 60% of the annual total. Activity for the first quarter of 2015 includes running two to three drilling rigs in the Wapiti area, ongoing completion and well tie-in activities, and constructing the Elmworth compressor station.

We will hold this pace of spending until the middle of the second quarter of 2015, where we will re-evaluate the capital program upon entering the spring breakup period. We have a high level of flexibility to further reduce the remaining 2015 capital spending plan if needed, in order to maintain balance sheet strength and maximize value in tune with market conditions at that time. Alternatively, should conditions warrant, we could scale up our capital program quickly and efficiently to take advantage of lower service costs and growth opportunities.

Our production guidance range for 2015 is unchanged at 22,500 to 24,000 Boe/d and we anticipate production in the range of 22,000 to 23,000 Boe/d for the first half of 2015. We would also like to affirm that our revised 2015 and 2016 production estimate in this environment is forecast to be sufficient to fulfill essentially all Take or Pay ("TOP") obligations with midstream companies as a result of the flexible terms which we have put in place previously. Despite reduced spending in this environment, our long term plans for 2016 and beyond still remain solid and intact.

NuVista is pleased to have delivered strong reserves and production growth in 2014, with metrics which showcase the high value and significant running room of the Wapiti Montney play. We will make the necessary adjustments to weather this low commodity price environment with strength and patience, while limiting capital spending to prudently protect our balance sheet. We are fortunate that the Wapiti Montney play is among the most prolific and economic in North America, and this may prove even more important during poor commodity price periods than in favorable periods. We would like to take this opportunity to thank our shareholders, our Board, and our staff for their support and dedication as we continue to build an ever more valuable future for NuVista.

Corporate Highlights

Three months ended
December 31,
Year ended
December 31,
($ thousands, except per share) 2014 2013 2014 2013
Financial
Oil and natural gas revenue 72,050 57,143 259,107 213,469
Funds from operations (1) 36,703 21,533 109,975 75,306
Per basic and diluted share 0.26 0.17 0.81 0.63
Net loss (42,478 ) (47,405 ) (58,881 ) (61,144 )
Per basic and diluted share (0.31 ) (0.38 ) (0.43 ) (0.51 )
Adjusted net earnings (loss) (1) 1,066 (4,245 ) (3,569 ) (20,133 )
Per basic and diluted share 0.01 (0.03 ) (0.03 ) (0.17 )
Total assets 1,024,080 905,711
Long-term debt, net of adjusted working capital (1) 183,770 47,495
Capital expenditures 67,968 80,011 312,208 224,389
Property acquisitions 35,075 - 45,237 2,183
Proceeds on property dispositions 69,377 17,878 81,550 30,270
Weighted average common shares outstanding (thousands):
Basic and diluted 138,579 125,411 136,497 120,430
Operating
Production
Natural gas (MMcf/d) 94.6 73.9 75.9 71.8
Condensate (Bbls/d) 4,732 2,500 3,137 1,925
Butane (Bbls/d) 544 482 540 458
Propane (Bbls/d) 780 712 687 710
Ethane (Bbls/d) 937 744 769 801
Oil (Bbls/d) 401 1,280 613 1,478
Total oil equivalent (Boe/d) 23,165 18,034 18,391 17,329
Average product prices (2)
Natural gas ($/Mcf) 3.77 3.40 4.19 3.28
Condensate ($/Bbl) 73.10 85.26 87.30 93.27
Butane ($/Bbl) 40.22 58.34 52.40 58.62
Propane ($/Bbl) 23.10 40.51 37.49 28.16
Ethane ($/Bbl) 13.96 10.91 14.15 9.42
Oil ($/Bbl) 67.95 71.46 86.77 78.48
Operating expenses ($/Boe) 10.92 11.16 11.22 11.70
Operating netback ($/Boe) 20.41 17.99 21.21 16.54
Funds from operations netback ($/Boe) (1) 17.22 12.99 16.39 11.91
Share trading statistics
High 10.83 7.57 12.47 8.40
Low 5.89 6.11 5.89 5.16
Close 7.41 7.14 7.41 7.14
Average daily volume 594,394 436,143 486,250 360,536
NOTES:
(1) Funds from operations, revenue, funds from operations per share, funds from operations netback, operating netback, adjusted net earnings, adjusted net earnings per share and adjusted working capital are not defined by GAAP in Canada and are referred to as non-GAAP measures. Funds from operations are based on cash flow from operating activities as per the statement of cash flows before changes in non-cash working capital and asset retirement expenditures. Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings (loss) per share. Funds from operations netback equals the total of revenues including realized commodity derivative gains/losses less royalties, transportation, operating, general and administrative, restricted stock units, interest expenses and cash taxes calculated on a Boe basis. Adjusted net earnings equals net earnings excluding after tax unrealized gains (losses) on commodity derivatives, impairments, impairment reversals, goodwill impairments and gains (losses) on property divestments. Operating netback equals the total of revenues including realized commodity derivative gains/losses less royalties, transportation and operating expenses calculated on a Boe basis. Adjusted working capital is current assets less current liabilities and excludes the current portions of the commodity derivative asset or liability. Long-term debt, net of adjusted working capital is calculated as long-term debt plus adjusted working capital. Total Boe is calculated by multiplying the daily production by the number of days in the period. For more details on non-GAAP measures, including reconciliation to GAAP measures refer to NuVista's "Management's Discussion and Analysis".
(2) Product prices exclude realized gains/losses on commodity derivatives.

Summary of Corporate Reserves Data

The following table outlines NuVista's corporate finding and development costs in more detail:

3 Year-Average (1) 2014 (1) 2013 (1)
Proved plus Proved plus Proved plus
Proved probable Proved probable Proved probable
After reserve revisions and including changes in future development capital
Finding and development costs ($/Boe) $14.75 $11.64 $13.67 $10.55 $14.51 $12.31
(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year.

The following table provides summary reserve information based upon the GLJ Report using the published GLJ January 1, 2015 price forecast set forth later in this document:

Natural Gas Condensate Other
Liquids (2)
Oil Total
Reserves category (1) Working
Interest
(MMcf)
Working
Interest
(MBbls)
Working
Interest
(MBbls)
Working
Interest
(MBbls)
Working
Interest
(MBoe)
Proved
Developed producing 135,706 5,727 4,162 604 33,110
Developed non-producing 43,623 1,469 823 465 10,027
Undeveloped 279,866 15,011 5,876 337 67,868
Total proved 459,195 22,207 10,861 1,405 111,006
Probable 447,541 22,484 10,519 1,248 108,842
Total proved plus probable 906,736 44,691 21,380 2,654 219,847
(1) Numbers may not add due to rounding.
(2) Propane, Butane, Ethane.

The following table is a summary reconciliation of the 2014 year end working interest reserves with the working interest reserves reported in the 2013 year end reserves report:

Natural Gas (1) (MMcf) Liquids (1) (MBbls) Oil (1) (MBbls) Total Oil
Equivalent (1) (MBoe)
Total proved
Balance, December 31, 2013 330,507 22,756 2,615 80,456
Exploration and development (2) 197,825 15,586 92 48,649
Technical revisions 14,730 (504 ) (129 ) 1,822
Acquisitions - - - -
Dispositions (56,213 ) (2,898 ) (963 ) (13,229 )
Production (27,654 ) (1,873 ) (209 ) (6,691 )
Balance, December 31, 2014 459,195 33,068 1,405 111,006
Total proved plus probable
Balance, December 31, 2013 566,655 39,928 4,860 139,230
Exploration and development (2) 409,773 32,053 146 100,495
Technical revisions 37,604 77 (454 ) 5,889
Acquisitions - - - -
Dispositions (79,642 ) (4,114 ) (1,689 ) (19,077 )
Production (27,654 ) (1,873 ) (209 ) (6,691 )
Balance, December 31, 2014 906,736 66,071 2,653 219,847
(1) Numbers may not add due to rounding.
(2) Reserve additions for drilling extensions, infill drilling and improved recovery.

The following table summarizes the future development capital included in the GLJ Report:

($ thousands, undiscounted) Proved Proved plus
probable
Balance, December 31, 2013 587,069 1,027,761
Dispositions (96,681 ) (123,156 )
Exploration and development 377,725 809,786
Balance, December 31, 2014 868,113 1,714,391

Summary Wapiti Montney Play Reserves Data

The following table summarizes the reserves for the Wapiti Montney play based upon the GLJ Report using the published GLJ January 1, 2015 price forecast set forth below (with comparatives at January 1, 2014 price forecast):

December 31, 2014 December 31, 2013
Reserves category Working Interest
(Mboe)
Working Interest
(Mboe)
Proved producing 20,000 9,716
Total proved 89,349 46,068
Total proved plus probable 183,703 86,174

The following table summarizes the future development capital for the Wapiti Montney play included in the GLJ Report:

($ thousands, undiscounted) Proved Proved plus
probable
Balance, December 31, 2013 449,016 801,109
Dispositions (19,228 ) (21,990 )
Exploration and development 386,291 792,836
Balance, December 31, 2014 816,079 1,571,955

The estimates of reserves for the Wapiti Montney play may not reflect the same confidence level as estimates of reserves of all NuVista's properties due to the effect of aggregation.

Summary of Corporate Net Present Value Data

The estimated net present values of future net revenue before income taxes associated with NuVista's reserves effective December 31, 2014 and based on published GLJ future price forecast as at January 1, 2015 as set forth below are summarized in the following table:

The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.

Before income taxes
Discount factor (%/year)
Reserves category (1)(2) ($ thousands) 0% 5% 10% 15% 20%
Proved
Developed producing 592,507 448,911 364,552 309,899 271,789
Developed non-producing 159,893 110,015 82,703 65,838 54,470
Undeveloped 1,067,785 570,215 321,255 183,054 100,274
Total proved 1,820,186 1,129,141 768,510 558,790 426,533
Probable 2,337,846 1,141,376 637,223 384,409 241,337
Total proved plus probable 4,158,032 2,270,517 1,405,733 943,199 667,869
(1) Numbers may not add due to rounding.
(2) Estimate future net revenues of reserves do not represent the fair market value of reserves.

The following table is a summary of pricing and inflation rate assumptions based on published GLJ forecast prices and costs as at January 1, 2015:

Natural Gas Liquids Oil
Year AECO Gas Price ($Cdn/ Mmbtu) Edmonton Condensate ($Cdn/Bbl) Edmonton Propane ($Cdn/Bbl) Edmonton Butane ($Cdn/Bbl) WTI Cushing Oklahoma ($US/Bbl) Edmonton Par Price 40 API ($Cdn/Bbl) Inflation Rates %
/ Year (1)
Exchange Rate (2) ($US/$Cdn)
Forecast
2015 3.31 69.24 19.63 52.91 62.50 64.71 2.0 0.850
2016 3.77 85.60 32.00 60.80 75.00 80.00 2.0 0.875
2017 4.02 91.71 38.57 65.14 80.00 85.71 2.0 0.875
2018 4.27 97.83 41.14 69.49 85.00 91.43 2.0 0.875
2019 4.53 103.94 43.71 73.83 90.00 97.14 2.0 0.875
2020 4.78 110.06 46.29 78.17 95.00 102.86 2.0 0.875
2021 5.03 113.62 47.78 80.70 98.54 106.18 2.0 0.875
2022 5.28 115.89 48.74 82.31 100.51 108.31 2.0 0.875
2023 5.53 118.20 49.71 83.96 102.52 110.47 2.0 0.875
2024 5.71 120.56 50.70 85.63 104.57 112.67 2.0 0.875
2025+ +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 2.0 0.875
(1) Inflation rate for costs.
(2) Exchange rate used to generate the benchmark reference prices in this table.

For full disclosure, information regarding our 2014 Year End Reserves and Economic Contingent Resources Evaluations will be filed on SEDAR and can also be accessed on our website at www.nuvistaenergy.com on March 9, 2015.

ADVISORY REGARDING OIL AND GAS INFORMATION

This news release contains the terms barrels of oil equivalent ("Boe"). Natural gas is converted to a Boe using six thousand cubic feet of gas to one barrel of oil. Boes may be misleading, particularly if used in isolation. The foregoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 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 conversion ratio on a 6:1 basis may be misleading as an indication of value.

Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.

NuVista has presented certain typecurves and well economics which are based on NuVista's historical production in the Bilbo and Elmworth development areas, in addition to production history from analogous Montney developments located in close proximity to the Wapiti area. Such typecurves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however, such typecurves and well economics are not necessarily determinative of the production rates and performance of existing and future wells. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the typecurves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills.

This press release discloses drilling locations in two categories: (i) proved and/or probable reserves locations; and (ii) Contingent Resources locations. Proved and probable locations and Contingent Resources locations are derived from the Corporation's most recent independent reserves and resources evaluation as prepared by GLJ as of December 31, 2014 and account for drilling locations that have associated proved and/or probable reserves or Contingent Resources, as applicable. There is no certainty that NuVista will drill all drilling locations and if drilled there is no certainty that such locations will result in additional production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory, oil and natural gas prices, costs, actual drilling results and other factors.

ADVISORY REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

This press release contains forward-looking statements and forward-looking information (collectively, "forward-looking statements") within the meaning of applicable securities laws. The use of any of the words "will", "expects", "believe", "plans", "potential" and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this press release contains forward looking statements, including management's assessment of: NuVista's future strategy, plans, opportunities and operations; forecast production; production mix; drilling, development, completion and tie-in plans and timing and results thereof; expectations of timing of construction of facilities and the benefits thereof; ability to fulfill all TOP obligations; plans to limit capital spending to manage NuVista's balance sheet and maximize value, commodity price expectations, future processing capacity, future drilling and completions costs;
NuVista's assessment of field conditions; typecurves; condensate and natural gas liquid yields; the timing, allocation and efficiency of NuVista's capital program and the results therefrom; the anticipated potential of NuVista's asset base;
reserves life indexes; and industry conditions. By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and funds from operations, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; and including, without limitation, those risks considered under "Risk Factors" in our Annual Information Form. 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. NuVista'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 NuVista will derive therefrom. NuVista 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.

CONSOLIDATED FINANCIAL STATEMENTS AND MD&A

December 31, 2014 audited consolidated financial statements and notes to the consolidated financial statements and Management's Discussion and Analysis for NuVista Energy Ltd. will be filed on SEDAR ( www.sedar.com ) under NuVista Energy Ltd. on Monday, March 9, 2015 and can also be accessed on NuVista's website at www.nuvistaenergy.com .

RESERVES AND RESOURCES ADVISORIES

The reserves and resources estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and are effective as of December 31, 2014. All reserves and resources information has been presented on a gross basis, which are the Company's working interest share before deduction of royalties and without including any royalty interests of the Company. The reserves and resources have been categorized accordance with the reserves and resource definitions as set out in the COGE Handbook.

The Company has presented certain estimates of Contingent Resources and Economic Contingent Resources ("ECR"). The following is the definition of Contingent Resources and Economic Contingent Resources as provided in the COGE Handbook:

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources or that any portion of the volumes currently classified as Contingent Resources will be produced. The recovery and resource estimates provided herein are estimates. The volumes of Contingent Resources that may be re-classified as Reserves and future production from such Contingent Resources may be greater than or less than the estimates provided herein.

Economic Contingent Resources ("ECR") are those Contingent Resources that are currently economically recoverable based on specific forecasts of commodity prices and costs.

The resources estimates contained herein have been presented on best estimate basis, which represents the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that quantities actually recovered will equal or exceed the best estimate.

The primary contingency that prevents the classification of the ECR as reserves is for additional drilling, completion and testing to occur and confirm viable commercial rates. Proved or proved and probable reserves were assigned by GLJ for areas in the immediate vicinity of producing or tested wells. ECR were assigned by GLJ beyond areas that were assigned reserves but within 3 miles of existing wells. As continued delineation drilling occurs, some resources currently classified as ECR are expected to be re-classified as Reserves. An additional contingency is the lack of infrastructure to facilitate full development in the short term, including the necessary facilities for gas gathering and processing and for the extraction of natural gas liquids. The re-classification of the ECR as Reserves is also subject to various non-technical contingencies which must be overcome such as lack of markets, legal, environmental and political concerns surrounding the possible banning of hydraulic fracturing, a technology required to develop the ECR, and other operational risks applicable to oil and gas issuers.

Volumes of resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. The currently producing assets of NuVista and other industry parties in the Wapiti Montney area are used as performance analogs for ECR within these areas. The evaluation of ECR is based on an independent third party evaluation that assumes that the vast majority of Nuvista's ECR will be recovered using horizontal multistage hydraulic fracturing using multi-well pad drilling, which is an established technology.

Continuous resource assessment through multi-year delineation and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fracking technology and applications. For ECR to be converted to reserves, management and the board of NuVista need to ascertain commercial production rates, then develop firm plans, including timing, infrastructure, and the commitment of capital. Confirmation of commercial productivity is generally required before the company can prepare firm development plans and commit required capital for the development of the ECR.

See "Reserves and Resource Disclosure" and the disclosure under the heading "Risk Factors" in the Annual Information Form, which will be filed on SEDAR ( www.sedar.com ) under NuVista Energy Ltd. on or before March 31, 2015.

NuVista Energy Ltd.
Jonathan A. Wright
President and CEO
(403) 538-8501

NuVista Energy Ltd.
Ross L. Andreachuk
VP, Finance and CFO
(403) 538-8539

3MV Energy Announces Extension to Convertible Debenture

/THIS NEWS RELEASE IS NOT FOR DISSEMINATION IN THE UNITED STATES OR TO ANY UNITED STATES NEWS SERVICES./

CALGARY , March 6, 2015 /CNW/ - 3MV Energy Corp. (" 3MV " or the " Company ") (TSXV: TMV) is pleased to announce that it has agreed to amend and extend its outstanding $2,000,000 secured convertible debentures (the " Debentures "). The Debentures term will be extended for one year from original expiry and mature on February 21, 2016 .  The Debentures will be convertible at any time until maturity into common shares of the Company at a conversion price of $0.25 per share.  Dallas Duce, a director and control person of 3MV, is the sole indirect holder of the Debentures.

The Debenture extension and amendment is subject to acceptance of the TSX Venture Exchange.

About 3MV

3MV is an oil and gas exploration and development company with assets throughout west central Saskatchewan's Viking oil play.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE 3MV Energy Inc.

Platino Swaps Putumayo Working Interest for Royalty

CALGARY, ALBERTA--(Marketwired - March 6, 2015) -

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.

Platino Energy Corp. (TSX VENTURE:PZE) (" Platino " or the " Company ") is pleased to announce that it has entered into an agreement with Vetra Exploracion y Produccion Colombia S.A.S ("Vetra"), on the Put-8 block.

Subject to approval by Colombia's National Hydrocarbon Agency ("ANH"), Platino will assign it's 50% working interest in the Put-8 block to Vetra in return for a 7% Gross Over Riding Royalty ("GORR"). The 7% GORR would be calculated on 100% of the block's production post deduction of any government royalties.

In addition, this agreement is subject to other customary closing conditions which would have to be met by July 31, 2015.

About Platino

Platino is a Calgary, Alberta headquartered resource company engaged in the exploration for, and the acquisition, development and production of hydrocarbons in Colombia.

Forward-Looking Statements

Certain statements contained in this news release constitute forward-looking information and statements within the meaning of applicable Canadian securities laws (collectively, "forward looking information"). The use of any of the words "expect", "anticipate", "may", "will", "intends" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: (i) the completion of the transaction; (ii) the potential for oil and gas production from the Put-8 block; (iii) the approval of the transaction by the ANH and the completion of various closing conditions set in the agreement by July 31, 2015; and (iv) other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

Various material factors, expectations and assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information throughout this news release including, without limitation expectations and assumptions relating to: (i) the ability of the parties to receive regulatory and third party approvals, as applicable, necessary for the completion of the transaction and the timing of receipt of such approvals; (ii) future industry and economic conditions and areas for growth and development; (iii) commodity prices, foreign currency exchange rates and interest rates; (iv) capital expenditure programs and other expenditures; (v) supply and demand for oil and natural gas; (vi) Platino's future operating and financial results; and (viii) treatment under governmental regulatory regimes and tax, environmental and other laws.

The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: (i) volatility in market prices for oil and natural gas; (ii) volatility in exchange rates for the U.S. dollar relative to other world currencies; (iii) liabilities and risks inherent in the oil and gas industry; (iv) competition for, among other things, capital, transportation capacity and skilled personnel; (v) changes in general economic, market and business conditions in Colombia and worldwide; (vi) actions by governmental or regulatory authorities (both domestic and foreign), including changes in tax laws and the risk of nationalization and expropriation of assets; (vii) the impact of adverse weather on the operations of Platino and its subsidiaries; and (viii) increases and overruns in operating costs. The outcome and timing of the proposed transaction may differ from that currently anticipated by Platino and regulatory and exchange approvals may not be obtained on the timelines anticipated or at all. Platino cautions that the foregoing list of assumptions, risks and uncertainties is not exhaustive.

Additional information on these and other factors that could affect the operations or financial results of Platino are included in the Listing Application (Form 2B) of Platino filed with the TSX Venture Exchange ("TSXV"), which has been filed with applicable securities regulatory authorities and may be accessed through the SEDAR website www.sedar.com . The forward-looking information contained in this news release is made as of the date hereof and Platino undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

The TSXV has in no way passed upon the merits of the proposed Transaction and has neither approved nor disapproved the contents of this press release. Neither the TSXV not its Regulation Services Provider (as that term is defined in the policies of the TSXV) accepts responsibility for the adequacy or accuracy of this release.

Platino Energy Corp. - Bogota
Tomas Villamil
President & Chief Executive Officer
+57(1) 235-0007

Platino Energy Corp. - Calgary
Rafi Khouri
Vice President, Business Development
+1(403) 262-6046

Mart Resources, Inc.: Operations and January 2015 Production Update

CALGARY, ALBERTA--(Marketwired - March 6, 2015) -

  • Umusadege field production averaged 17,050 barrels of oil per day ("bopd") during January 2015 based on calendar days; average field production based on production days was approximately 18,070 bopd during January 2015.
  • Total production from the Umusadege field in January 2015 was approximately 528,560 barrels of oil ("bbls").
  • The combined net delivery of oil from the Umusadege field through the Umugini pipeline and the Nigerian Agip Oil Company Limited ("NAOC") export pipeline totaled approximately 525,920 bbls in January 2015 before estimated combined pipeline and export facility losses, and approximately 450,430 bbls after deduction of combined pipeline and export facility losses for January 2015 as estimated by Mart.
  • Aggregate calculated downtime during January 2015 totaled approximately 1.8 days.
  • Mart is working with its Nigerian lender towards a restructuring of future principal payments scheduled in 2015.

Mart Resources, Inc. (TSX:MMT) ("Mart" or the "Company") and its co-venturers, Midwestern Oil and Gas Company Limited ("Midwestern", Operator of the Umusadege field) and SunTrust Oil Company Limited are providing the following updates on Umusadege field production for January 2015 and other operations.

January 2015 Aggregate Production Update

Umusadege field production during January 2015 averaged approximately 17,050 bopd resulting in total production of approximately 528,560 bbls for the month. Aggregate calculated Umusadege field downtime during January 2015 was approximately 1.8 days (based upon days with production of more than 10,000 bopd being considered to have no downtime). Although shutdowns of both the NAOC and Trans Forcados export pipelines were experienced during January 2015 due to operational interruptions for general pipeline repairs and maintenance and due to vandalism, ongoing production from the Umusadege field was minimally affected due of the ability of the field operator to alternate production between the two pipelines. There were no full down days during January. The average field production based on producing days was approximately 18,070 bopd in January 2015.

The combined net delivery of oil from the Umusadege field through the new Umugini pipeline and NAOC export pipeline totaled approximately 525,920 bbls in January 2015 before estimated pipeline and export facility losses, and approximately 450,430 bbls after deduction of combined pipeline and export facility losses estimated for January 2015 by Mart. Combined delivery of oil from the Umusadege field through the Umugini pipeline and NAOC export pipeline reached a record one-day volume of approximately 29,000 bopd in late January 2015.

NAOC Export Pipeline Update

Total net crude oil deliveries into the NAOC export pipeline from the Umusadege field for January 2015 were approximately 306,960 bbls before pipeline losses. Based upon the 12-month rolling average rate of pipeline and export facility losses from December 2013 to November 2014 of 17.46%, Mart estimates NAOC pipeline and Brass River export facility losses for January 2015 will be approximately 53,590 bbls. Accordingly, Mart estimates that the total net crude deliveries into the NAOC export pipeline from the Umusadege field for January 2015 less estimated pipeline losses will be approximately 253,370 bbls.

As previously announced, total net crude oil deliveries into the NAOC export pipeline from the Umusadege field for December 2014 were approximately 295,392 bbls. Actual NAOC pipeline and export facility losses have not been allocated for December 2014 because allocation was suspended by the Department of Petroleum Resources pending an approved loss computation formula. Mart previously estimated pipeline and export facility losses for December 2014 to be approximately 51,568 bbls, based upon the 12-month rolling average rate of pipeline and export facility losses of 17.46% between December 2013 and November 2014.

Umugini Pipeline Update

Mart and its co-venturers have not yet received official reports from the operators of the Trans Forcados export pipeline or the Forcados oil export terminal stating actual oil injection volumes or pipeline and export facility losses for the Trans Forcados export system. Based upon Mart's internal production and facility data, the Company estimates that Umusadege field deliveries into the Trans Forcados export pipeline connected to the Forcados oil export terminal were approximately 218,960 bbls in January 2015. Based upon historic pipeline losses encountered by other exploration and production companies utilizing the Trans Forcados export system, Mart estimates pipeline and export facility losses of 10% of crude oil deliveries, resulting in estimated Umusadege field deliveries of approximately 197,060 bbls for January 2015 after deduction of estimated pipeline and export facility losses.

Update on Debt Repayment Obligations to Nigerian Lender

As previously described in Mart's Consolidated Financial Statements and Management's Discussion and Analysis for the period ended September 30, 2014, Mart, through its wholly-owned Nigerian subsidiary Mart Umusadege Resources Nigeria Limited, has a $232.5 million term loan facility with Guaranty Trust Bank (" GTB ") of Nigeria. As of February 28, 2015, the total outstanding balance under this term loan facility is approximately $201.1 million of which approximately $119.1 million relates to the OML 18 acquisition and $82 million to Umusadege field development and working capital funding. Approximately $68.2 million is payable during the period from March 1, 2015 to December 31, 2015 of which approximately $8.5 million net is payable during March 2015. Mart is currently working with GTB towards a restructuring and deferral of principal payments scheduled in 2015.

Drilling update

After completion of drilling and testing of the Umu-13 well in January 2015 the drill rig has been on standby while reviewing the 2015 capital expenditure program and restructuring the loan facility.

Additional information regarding Mart is available on the Company's website at www.martresources.com and under the Company's profile on SEDAR at www.sedar.com .

Except where expressly stated otherwise, all production figures set out in this press release, including bopd, reflect gross Umusadege field production rather than production attributable to Mart. Mart's share of total gross production before taxes and royalties from the Umusadege field fluctuates between 82.5% (before capital cost recovery) and 50% (after capital cost recovery).

Forward Looking Statements and Risks

Certain statements contained in this press release constitute "forward-looking statements" as such term is used in applicable Canadian and US securities laws. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or are not statements of historical fact and should be viewed as "forward-looking statements". These statements relate to analyses and other information that are based upon forecasts of future results, estimates of amounts not yet determinable and assumptions of management. Such forward looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

In particular, there is no assurance that there will not be future disruptions of the NAOC export pipeline or Brass River export facility. Any future disruptions may materially and adversely affect the ability of the Company to transport, deliver and sell its crude oil production from the Umusadege field. Pipeline and export facilities losses are expected to continue in the future and such losses could be material. There is no assurance that there will not be adjustments to previously reported pipeline and export facilities losses by NAOC. There is no assurance that the estimates of current month pipeline and export facilities losses will reflect actual losses once reported to the Company by NAOC.

There is no assurance that there will not be future disruptions to the Umugini Pipeline, Trans Forcados export pipeline or the Forcados export terminal. Any future disruptions may materially and adversely affect the ability of the Company to transport, deliver and sell its crude oil production from the Umusadege field. Record daily volumes of oil deliveries referenced herein are not necessarily indicative of future monthly average daily oil delivery volumes. There is no assurance on when the operators of the Trans Forcados export system will report actual oil injections or pipeline and export facility losses to the Company or that the estimates of the Company regarding oil injection volumes or pipeline and export facility losses will reflect those volumes and losses reported by the operators of the Trans Forcados export system to the Company. The Umugini pipeline is a new pipeline and will continue to face risk associated with any new pipeline installation and with risks generally associated with pipeline operations in Nigeria.

There is no assurance that Mart will be able to restructure its term loan facility with GTB or defer the scheduled payment date of any of the principal payments. There is no assurance that Mart will be able to make the principal or interest payments when due.

There can be no assurance that such forward-looking statements will prove to be accurate as actual results and future events could vary or differ materially from those anticipated in such statements. Accordingly, readers should not place undue reliance on forward-looking statements contained in this news release. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Forward-looking statements are made based on management's beliefs, estimates and opinions on the date the statements are made and the Company undertakes no obligation to update forward-looking statements and if these beliefs, estimates and opinions or other circumstances should change, except as required by applicable law.

NEITHER THE TSX NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THE RELEASE.

Mart Resources, Inc. - London, England
Dmitri Tsvetkov
CFO
+44 207 351 7937
[email protected]

Mart Resources, Inc. - Canada
Sam Grier
403-270-1841
[email protected]
www.martresources.com

Vermilion Energy Inc. Announces Filing of Annual Information Form and Annual Report

CALGARY , March 6, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announces the filing of its Annual Information Form ("AIF") for the year ended December 31, 2014 on the System for Electronic Document Analysis and Retrieval ("SEDAR").  The AIF contains Vermilion's Statement of Reserves Data and Other Oil and Gas Information as required under National Instrument 51-101.  Vermilion has also filed its Annual Report which includes its audited consolidated financial statements and Management's Discussion and Analysis for the year ended December 31, 2014 , copies of which have also been separately filed on SEDAR.

These documents can be found on the SEDAR website at www.sedar.com and also on the Company's website at http://www.vermilionenergy.com/ir/reports-filings.cfm

Vermilion is an oil-leveraged producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in Western Canada , Europe and Australia . Our business model targets annual organic production growth of 5% or more along with providing reliable and increasing dividends to investors.  Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Western Canada , the exploration and development of high impact natural gas opportunities in the Netherlands and Germany , and through drilling and workover programs in France and Australia.  Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland.  Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.  Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance.  Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

SOURCE Vermilion Energy Inc.

Jericho Oil Closes on its Initial Oklahoma Acquisition

VANCOUVER , March 6, 2015 /CNW/ - Jericho Oil Corporation ("Jericho" or the "Company") (TSX-V: JCO, OTCQX: JROOF), a growth-oriented oil company engaged in the acquisition, exploration, development and production of overlooked and undervalued oil properties in the U.S., has closed on its previously announced acquisition of a 50% working interest in 1,850 acres in northeastern Oklahoma.  This is the first acquisition for Jericho in the state of Oklahoma and represents the emergence of its second platform.  The asset brings Jericho's total acreage position to 5,600 acres.  Jericho will begin to assess and inventory the current infrastructure and then move on to the process of reworking and reactivating existing wellbores.

Allen Wilson , CEO of Jericho, said, "We believe our 'patiently aggressive' approach has begun to payoff.  The market's turbulent conditions have provided us with the opportunity to acquire assets with positive, long-term potential at discounted prices.  Our current situation provides us the ability to act accordingly when these types of opportunities present themselves and it is our intention to continue to do so long as oil prices remain unsettled."

About Jericho Oil Co r poration

Jericho is focused on growth through consistent, predictable and repeatable high margin conventional oil production by bringing new and proven technology to legacy, onshore basins in the U.S. Jericho has acquired a 50% interest in approximately 5,600 acres. Jericho will provide updates as their program progresses. For more information, please visit www.jerichooil.com .

Cautionary Note Regarding Forward-Looking Statements
This news release includes certain "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and Canadian securities laws. There can be no assurance that such statements will prove to be accurate and actual results and future events could differ materially from those anticipated in such statements. Important factors that could cause actual events and results to differ materially from Jericho's expectations include risks related to the exploration stage of Jericho's project; market fluctuations in prices for securities of exploration stage companies; and uncertainties about the availability of additional financing.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE Jericho Oil Corporation

Cygam Announces Corporate Update

CALGARY, ALBERTA--(Marketwired - March 6, 2015) - Cygam Energy Inc. (TSX VENTURE:CYG) ("Cygam" or the "Company") announced that on February 10, 2015, Cygam's Board of Directors met to identify, examine and consider strategic alternatives available to the Company, including, the sale of the Company, merger or other business combination, recapitalization, sale of all or a portion of the Company's assets, appointment of a receiver of the Company and/or its business or any combination thereof. Ultimately, the Board of Directors determined that the Company would cease all funding in respect of its Tunisian operations and terminate the employment of its Tunisian employees.

This announcement coincides with the release on SEDAR of a material change report which was previously filed on a confidential basis with securities regulators. The report was filed confidentially to allow Cygam time to reach an agreement with a third party for the disposition of certain of Cygam's Tunisian assets. The parties were unable to reach an agreement in the time required by the board of directors of Cygam. The Company will continue to consider alternatives with third parties with respect to its Tunisian business and related assets.

Forward-Looking Statements

Certain information set forth in this press release, contains forward-looking statements including management's and the Board of Directors' assessment of future plans regarding the strategic review process. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "may", "intention", "estimate", "would", "will" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, strategic alternatives available to Company, the terms of any transaction between Cygam and one or more third parties, or timing or completion of any such transactions and matters related or incidental thereto. No assurance can be given that any transactions will be agreed to between Cygam and one or more third parties, or if agreed, be acceptable to those from whom consent or approval will be necessary. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Cygam's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, delays resulting from or the inability to obtain required regulatory approvals, inability to retain and delays in retaining services, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, incorrect assessment of the value of transactions, failure to realize the anticipated benefits of transactions, ability to access sufficient capital from internal and external sources.

The foregoing list is not exhaustive. Additional information on these and other risks that could affect Cygam's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website ( www.sedar.com ), or at Cygam's website ( www.cygamenergy.com ). 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. The actual results, performance or achievement of Cygam could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Cygam will derive therefrom. Cygam 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 applicable securities laws.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

CYGAM Energy Inc
David Taylor
President and Chief Executive Officer
[email protected]

CYGAM Energy Inc
Al Robertson
Chief Financial Officer
(403) 802 6983
[email protected]
www.cygamenergy.com

Lightstream Announces 2014 Funds Flow From Operations of $572 Million

CALGARY, ALBERTA--(Marketwired - March 6, 2015) - Lightstream Resources Ltd. (the "Company" or "Lightstream") (TSX:LTS) announces fourth quarter and year-end 2014 financial and operating results.

HIGHLIGHTS

In this press release, annual comparisons are 2014 compared to 2013 and quarterly comparisons are fourth quarter 2014 compared to fourth quarter 2013, unless otherwise noted. All references to well counts are on a net basis.

  • Our 2014 proved plus probable ("2P") year-end reserve value has a net present value (before tax and discounted at 10%) of $3.2 billion ($2.6 billion after tax) as determined by Sproule Associates Limited, which significantly exceeded our $1.9 billion enterprise value (total debt plus equity market value) at December 31, 2014.
  • Average daily production for 2014 totaled 40,420 boepd (78% light-oil and liquids weighted) and 36,472 boepd (75% light-oil and liquids weighted) for Q4 2014 reflecting dispositions of 6,315 boepd completed through the first three quarters in 2014.
  • 2014 funds flow was $572 million ($2.86 per basic share) a 15% decrease from 2013; fourth quarter funds flow was $89 million ($0.45 per basic share), down 39% from the prior year on lower commodity prices and lower production (primarily as a result of dispositions).
  • Our operating netback for 2014 was $49.45/boe, 1% below our operating netback in 2013, and for the fourth quarter was $33.15/boe, down 27% from the fourth quarter of 2013 reflecting a 25% drop in US$ WTI prices over the same period.
  • Capital expenditures (before acquisitions and divestitures ("A&D")) were $472 million for 2014, 34% below 2013 levels, and $121 million for the fourth quarter of 2014, a decrease of 22% for the same period a year earlier.
  • Dispositions of non-core assets totaled $729 million with net proceeds applied to debt.
  • As a result of our disposition program and cash expenditures being 99% of funds flow, total debt was reduced to $1.65 billion as at December 31, 2014, a 28% decrease from the same time last year. We expect to realize at least $30 million in annual cash interest savings going forward.
  • For 2014, we reported a net loss of $446 million as a result of a non-cash $700 million impairment charge to property, plant and equipment, primarily due to reduced forward pricing estimates compared to year end 2013.
SUMMARY OF RESULTS
Three months ended
December 31,
Year ended
December 31,
2014 2013 2014 2013
Oil and natural gas revenue 186,861 287,727 1,107,824 1,250,491
Funds flow from operations (1) 89,278 146,017 572,232 670,928
Per share - basic ($) (1) 0.45 0.73 2.86 3.43
Adjusted Net income (loss) (1) 160,386 (45,598 ) 249,922 (42,608 )
Per share - basic ($) (1) 0.81 (0.23 ) 1.25 (0.22 )
Capital Expenditures (2) Net Capital Expenditures (1) 121,124
123,194
155,933
154,487
471,820
(240,636
) 715,913
719,101
Total debt (1) 1,646,862 2,274,122
Dividends per share ($) (1) 0.10 0.20 0.46 0.91
Cash dividends per share ($) (1) 0.10 0.17 0.46 0.67
Common Shares, end of period (000) 197,304 199,774
Operating netback ($/boe) (1) (3) (4) 33.15 45.43 49.45 50.00
Average daily production (boe) (3) 36,472 45,521 40,420 46,438
(1) Non-GAAP measure. See "Non-GAAP Measures" section in the 2014 Management's Discussion and Analysis.
(2) Prior to asset acquisitions and divestitures
(3) Six Mcf (thousand cubic feet) of natural gas is equivalent to one barrel of oil equivalent ("boe").
(4) Net of transportation expenses.

OPERATING SUMMARY

Primarily reflecting non-core asset dispositions of 6,315 boepd, total average production in 2014 decreased 13% to 40,420 boepd (78% light-oil and liquids weighted) from our average 2013 production of 46,438 boepd. Our fourth quarter average production of 36,472 boepd (75% light oil and liquids weighted) was 20% lower than average production in the fourth quarter of 2013, due primarily to the sale of our conventional assets in southeast Saskatchewan.

Our capital spending program for the year was $472 million, a 34% decrease from 2013 levels and a 50% decrease from 2012 levels. Capital expenditures in the fourth quarter were $121 million (before A&D), a decrease of 22% from the $156 million invested in the fourth quarter of 2013, reflecting our reduced capital program and commitment in 2014 to spend within cash flow. Capital spending has decreased significantly over the last several years which is consistent with our maturing asset base.

Production expenses for the fourth quarter decreased by 15% on a total basis compared to the same period in 2013 due primarily to lower variable production costs associated with decreased production levels and the disposition of our southeast Saskatchewan Conventional assets. On a per boe basis, production expenses increased to $13.47/boe for the quarter and $14.14/boe for 2014 as a result of additional well workovers.

AVERAGE DAILY PRODUCTION
Three months ended
December 31, 2014
Year ended
December 31, 2014
Business Unit Oil &NGL
(bbl/d)
Gas
(Mcf/d)
Total
(boe/d)
Oil &NGL
(bbl/d)
Gas
(Mcf/d)
Total
(boe/d)
Bakken (incl. Conventional) 12,912 6,467 13,990 16,632 7,148 17,823
Cardium 11,798 40,607 18,566 12,381 37,348 18,606
Alberta/BC 2,589 7,963 3,916 2,671 7,922 3,991
27,299 55,037 36,472 31,684 52,418 40,420

The Cardium business unit continues to be our most active area, followed by the Bakken business unit and finally Alberta/BC, more specifically Swan Hills. During 2014, we drilled 98 wells at a 100% success rate. We brought 88 wells on production, leaving an inventory of 13 wells at December 31, 2014, which we expect to have on production by the end of Q2 2015.

Q4 2014 DRILLING ACTIVITY
Drilled Completed On Production Inventory (1)
Business Unit Gross Net Gross Net Gross Net Gross Net
Bakken (incl. Conventional) 21 13 24 15 21 12 8 6
Cardium 18 15 19 15 17 13 9 7
Alberta/BC 2 1 2 1 2 1 - -
Total 41 29 45 31 40 26 17 13
(1) Inventory refers to the number of wells pending completion and/or tie-in at December 31, 2014.
2014 DRILLING ACTIVITY
Drilled Completed On Production Inventory (1)
Business Unit Gross Net Gross Net Gross Net Gross Net
Bakken (incl. Conventional) 58 39 54 34 52 31 8 6
Cardium 69 51 60 46 63 49 9 7
Alberta/BC 9 8 9 8 9 8 - -
Total 136 98 123 88 124 88 17 13
(1) Inventory refers to the number of wells pending completion and/or tie-in at December 31, 2014.

Southeast Saskatchewan

Our Bakken business unit averaged 13,990 boepd of production during the fourth quarter of 2014, representing a 17% decrease from Q4 2013 due to attenuation of investment in the area as we continue to maximize the free cash flow generated from this resource play. In 2014, this business unit generated $282 million of net operating income yielding $164 million of free cash flow after capital expenditures of $118 million. Prior to selling our conventional business unit these assets generated $56 million in free cash flow.

As previously announced, we are looking to monetize, at an appropriate valuation, all or part of our Bakken business unit over the next 12 - 24 months, which, if successful, would allow us to significantly transform our balance sheet and refocus Lightstream into an Alberta-based company with production of over 20,000 boepd (pro-forma Q4 2014 rates).
Cardium

Production in the Cardium business unit averaged 18,566 boepd during the fourth quarter of 2014, representing a 6% decrease from the same period last year. This was primarily driven by divestitures of 1,200 boepd in the first quarter of 2014. Prior to dispositions, Cardium production would have been largely unchanged with 26% lower capital spending. As a result, free cash flow in this business unit improved to $85 million in 2014 from $32 million in 2013 and we expect the Cardium to continue to be our largest producing business unit.

Alberta/BC

In Alberta/BC, fourth quarter production averaged 3,916 boepd, which represents a 7% decrease from Q4 2013 which can be largely attributed to 500 boepd of production that was sold during the first quarter 2014. This was partially offset by new well activity where we brought 7 operated Swan Hills wells on production in Q2 2014 and participated in 2 (1 net) non-operated wells in Q4 2014.

FINANCIAL RESULTS

In 2014 we successfully executed our planned non-core asset divestiture program generating total gross proceeds of $729 million at attractive metrics. These proceeds were used to reduce overall corporate debt levels by 28% to $1.65 billion and, as a result of this reduction, we also expect to realize at least $30 million in annual cash interest savings going forward. We exceeded our goal to be cash flow neutral with 2014 capital expenditures (before A&D) plus dividend payments being 99% of funds flow from operations.

Funds flow from operations was $572 million ($2.86 per basic share) for 2014, a 15% decrease from 2013 driven mostly by lower annual production, primarily due to asset sales. Our average operating netback in 2014 was $49.45/boe, a decrease of 1%, as higher oil and natural gas prices were offset by higher royalties and production expenses. For 2014 our average realized liquids price was $88.00/bbl (WTI price was US$93.00/bbl). Our Q4 operating netback was $33.15/boe, a 27% decrease from the same period last year primarily due to lower oil prices and slightly higher production expenses, partially offset by lower royalties.

In 2014, we recorded a net loss of $446 million compared to a net loss of $1,384 million in 2013. The loss in 2014 is the result of a non-cash impairment charge to property, plant and equipment of $700 million recognized in the fourth quarter, due to reduced forward commodity pricing estimates and negative probable reserve revisions.
In response to the rapid decline in world oil prices, we decreased our monthly dividend effective December 2014 and ultimately suspended our dividend effective January 2015. We continue to monitor oil price trends and will adjust our capital spending forecasts and dividend policy accordingly.

2015 GUIDANCE

Our revised guidance reflects a lower commodity price forecast. In the current commodity price and service cost environment, we do not intend to invest in operated, new well drilling programs in the second half of 2015. This is reflected in a 45% decrease in planned capital expenditures for the year compared to previous 2015 guidance, which has not impacted annual average production but is expected to reduce exit production. We continue to expect to realize excess funds flow relative to our capital program with any and all excess cash being applied to our debt. As previously stated, we are renegotiating debt terms with our credit facility lenders to manage our financial covenants and maintain financial flexibility.

($000s, except where noted and per share amounts) 2015 Guidance
(Revised Mar 6, 2015)
2015 Guidance
(Initial Dec 15, 2014)
%
Variance
Production (annual average)
Total (boe/d) 30,500 - 32,500 30,000 - 32,000 2%
Natural Gas Weighting 26% 23% 3%
Exit Production (boe/d) 26,500 - 28,500 30,000 - 32,000 (11%)
EBITDA 255,000 - 275,000 330,000 - 350,000 (22%)
Funds Flow from Operations 145,000 - 165,000 225,000 - 245,000 (34%)
Funds Flow per share (1) 0.74 - 0.84 1.14 - 1.24 (34%)
Dividends per share 0.00 0.48 (100%)
Capital Expenditures (2) 100,000 - 120,000 190,000 - 210,000 (45%)
Pricing Assumptions:
Crude oil - WTI (US$/bbl) (3) 52.50 65.00 (19%)
Crude oil - WTI (Cdn$/bbl) 65.63 74.71 (12%)
Corporate oil differential (%) 15 10 5%
Natural gas - AECO (Cdn$/mcf) 3.00 4.00 (25%)
Exchange rate (US$/Cdn$) 0.80 0.87 (8%)
(1) Funds flow per share calculation based on 197 million weighted average basic shares outstanding.
(2) Projected capital expenditures exclude acquisitions and divestitures, which are evaluated separately.
(3) Oil pricing assumption is $50/bbl WTI for first half of 2015 and $55/bbl WTI for second half.

2014 FOURTH QUARTER AND YEAR-END FINANCIAL RESULTS CONFERENCE CALL

Lightstream management will be hosting a conference call for investors, financial analysts, media and any interested persons on March 6, 2015, at 9:00 a.m. (Mountain Time) (11:00 a.m. Eastern Time) to discuss Lightstream's 2014 fourth quarter and annual financial and operating results.

The investor conference call details are as follows:

Live call dial-in numbers: 1-416-340-2216 / 1-800-355-4959
Replay dial-in numbers: 1-905-694-9451 / 1-800-408-3053
Passcode: 8559370
http://www.gowebcasting.com/6160

SELECTED QUARTERLY AND ANNUAL RESULTS FROM CONTINUING OPERATIONS

Three months ended
December 31,
Years ended
December 31,
2014 2013 %
Change
2014 2013 %
Change
Financial ($000s, except where noted)
Oil and natural gas sales 186,861 287,727 (35 ) 1,107,824 1,250,491 (11 )
Funds flow from operations (1) 89,278 146,017 (39 ) 572,232 670,928 (15 )
Per share - basic ($) (1) 0.45 0.73 (38 ) 2.86 3.43 (17 )
- diluted ($) (1) (2) 0.44 0.72 (39 ) 2.82 3.38 (17 )
Adjusted Net Income (loss) (1) 160,386 (45,598 ) (452 ) 249,922 (42,608 ) (687 )
Per share - basic ($) (1) 0.81 (0.23 ) (452 ) 1.25 (0.22 ) (668 )
- diluted ($) (1) (2) 0.80 (0.23 ) (448 ) 1.23 (0.22 ) (659 )
Dividends (1) 19,247 40,320 (52 ) 92,266 182,536 (49 )
Per share ($) (1) 0.10 0.20 (50 ) 0.46 0.91 (49 )
Payout ratio (1) 22% 28% - 16% 27% -
Cash dividends (1) 19,247 33,983 (43 ) 92,266 133,815 (31 )
Cash dividend payout ratio (1) 22% 23% 16% 20% -
Capital Expenditures (3) 121,124 155,933 (22 ) 471,820 715,913 (34 )
Net capital expenditures (1) 123,194 154,487 (20 ) (240,636 ) 719,101 (133 )
Sustainability Ratio (1) 99% 127% -
Total debt (1) (4) 1,646,862 2,274,122 (28 )
Basic common shares, end of period (000) 197,304 199,774 (1 )
Operations
Operating netback($/boe except where noted) (1) (5)
Oil, NGL and natural gas revenue (6) 55.38 68.29 (19 ) 74.65 73.35 2
Royalties 8.76 10.11 (13 ) 11.06 10.16 9
Production expenses 13.47 12.75 6 14.14 13.19 7
Operating netback 33.15 45.43 (27 ) 49.45 50.00 (1 )
Average daily production (boe/d)
Oil and NGL (bbl/d) 27,299 36,421 (25 ) 31,684 37,443 (15 )
Natural gas (mcf/d) 55,037 54,600 1 52,418 53,969 (3 )
Total (boe/d) (5) 36,472 45,521 (20 ) 40,420 46,438 (13 )
(1) Non-GAAP measure. See " Non-GAAP Measures " section in the 2014 Management's Discussion and Analysis.
(2) Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date.
(3) Prior to asset acquisitions and dispositions.
(4) Total debt is calculated as secured credit facility outstanding plus accounts payable less accounts receivable, prepaid expense and long-term investments plus the full value outstanding on the senior unsecured notes and convertible debentures converted to Canadian dollars at the exchange rate on the period end date.
(5) Six Mcf of natural gas is equivalent to one barrel of oil equivalent ("boe").
(6) Net of transportation expenses.

CORRECTION TO FEBRUARY 19, 2015 RESERVES RELEASE

There was an inadvertent input error which understated after-tax values reported in our February 20, 2015 press release. The previously reported and corrected values are below.

Net Present Value 2P Reserves - After Tax ($millions) (2)(3)
Forecast Prices (1)
As at December 31, 2014
0% 5% 10%
Reported $4,483 $3,071 $2,265
Revised 4,937 3,472 2,625
Variance ($) 454 401 360
Variance (%) 10% 13% 16%
Notes:
(1) Based on the Sproule price forecast effective December 31, 2014.
(2) Company working interest reserves value plus royalties received less royalties and burdens.
(3) Estimated values of future net revenue disclosed in this press release do not represent fair market values.

Lightstream Resources Ltd. is an oil and gas exploration and production company focused on light oil in the Bakken and Cardium resource plays. We are committed to delivering industry leading operating netbacks, strong cash flows and consistent operating results through leading edge technology applied to a multi-year inventory of existing and emerging resource play opportunities. Our long-term strategy is to efficiently develop our assets and deliver an attractive dividend yield.

Forward-Looking Statements . Certain information provided in this press release constitutes forward-looking statements. Specifically, this press release contains forward-looking statements relating to, but not limited to Lightstream's guidance for 2015 as outlined under the 2015 Guidance section, including planned capital spending, production targets and the anticipated product type weighting, expectations regarding our realized oil and natural gas prices, proposed exploration and development activities (including the number of wells to be drilled, completed and put on production); sources of capital; expectation that funds flow will exceed capital expenditures in 2015 and our plans to reduce debt with any excess funds flow; anticipated cash interest savings as a result of 2014 debt retirement; and a number of other matters including future results from operations; projected financial results and future capital and operating costs.

The forward-looking statements are based upon certain material factors and expectations and assumptions of Lightstream including, without limitation: that Lightstream will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes, the accuracy of the estimates of Lightstream's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate financing and cash flow to fund its planned expenditures. Although Lightstream believes the material factors, expectations and assumptions on which the forward-looking statements are based are reasonable, no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking statements in this press release are not guarantees of future performance and should not be unduly relied upon. Such statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements including, but not limited to: changes in commodity prices and exchange rates; general conditions in the oil and gas industry; operational risks in development, exploration and production; unanticipated operating results or production declines; delays or changes in exploration or development plans; the uncertainty of oil and gas reserve estimates; increase in costs; reliance on industry partners; risks that asset dispositions cannot be completed, availability of equipment and personnel; changes in tax or environmental laws, royalty rates or other regulatory matters; increased debt levels or debt service requirements; limited, unfavorable or lack of access to capital markets; a lack of adequate insurance coverage; and the impact of competition. Certain of these risks are set out in more detail in our Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com. Except as may be required by applicable securities laws, Lightstream assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

BOEs. Natural gas volumes have been converted to barrels of oil equivalent ("boe"). Six thousand cubic feet ("Mcf") of natural gas is equal to one barrel of oil equivalent based on an energy equivalency conversion method primarily attributable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.

Well Counts. All references to well counts are on a net basis.

Lightstream Resources Ltd.
John D. Wright
President and Chief Executive Officer
403.268.7800

Lightstream Resources Ltd.
Peter D. Scott
Senior Vice President and Chief Financial Officer
403.268.7800

Lightstream Resources Ltd.
Annie C. Belecki
General Counsel
403.268.7800

Lightstream Resources Ltd.
403.268.7800
403.218.6075 (FAX)
[email protected]
www.lightstreamresources.com

Perpetual Energy Inc. Releases Fourth Quarter and Year-End 2014 Financial and Operating Results

CALGARY , March 5, 2015 /CNW/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Company" or the "Corporation") is pleased to report its fourth quarter and year end 2014 financial and operating results. Perpetual continues to report year-over-year gains in production, revenue and funds flow, reflecting operational and financial success on our key diversifying strategies in the Greater Edson area for liquids-rich natural gas and at Mannville for heavy oil.  A focus on debt reduction in 2014 was successfully reflected in a 12 percent decrease in net debt at the end of 2014, as compared to the end of 2013, achieved with the monetization of future gas over bitumen ("GOB") royalty credits, property dispositions and execution of the East Edson joint venture ("East Edson JV").  Financial flexibility was further enhanced with the issuance of senior notes and early redemption of $125 million of convertible debentures in 2014 which extends the term for the majority of Perpetual's debt to 2018 and beyond.

A complete copy of Perpetual's audited consolidated financial statements and related Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2014 can be obtained through the Corporation's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com .

FOURTH QUARTER 2014 HIGHLIGHTS

Capital Spending and Property Dispositions

  • Capital expenditures of $26.0 million during the fourth quarter were focused on liquids-rich natural gas development at East and West Edson , start-up of a waterflood pilot project at Mannville and spending to prepare for the cyclic heat stimulation test planned as phase 1 of the LEAD (low pressure electro-thermally-assisted drive) pilot project for bitumen extraction at Panny.  At West Edson, two (1.0 net) wells were drilled, while at East Edson , fourth quarter development projects included nine (9.0 net) new wells drilled and on-going construction costs for the new East Edson gas plant.  Drilling operations at East Edson were primarily funded by the joint venture partner under the East Edson JV.
  • In November 2014 , Perpetual closed the disposition of non-core heavy oil properties in Eastern Alberta for net proceeds of $21.4 million , which included heavy oil Mannville reserves, undeveloped lands and estimated production of 400 boe/d.

Production Highlights

  • Fourth quarter average production of 23,685 boe/d increased 21 percent quarter over quarter (Q3 2014 – 19,640 boe/d) and 28 percent relative to the comparative 2013 quarter (Q4 2013 - 18,559 boe/d), resulting in a 2014 exit rate of approximately 24,150 boe/d, 30 percent higher than the Company's 2013 exit production rate.
  • Natural gas production of 122.5 MMcf/d was 36 percent higher than the fourth quarter of 2013, reflecting production from new wells drilled in the Greater Edson area.  At West Edson, increased production from new wells held the Company-operated West Edson gas plant at or above full capacity of 60 MMcf/d (30 MMcf/d net) plus associated C5+ liquids.  Continued drilling at East Edson under the East Edson JV similarly increased production to fully utilize existing compression and processing facilities at just over 30 MMcf/d plus associated liquids of 15 to 20 bbl per MMcf.
  • Oil and natural gas liquids ("NGL" or "liquids") production of 3,262 bbl/d was seven percent below the fourth quarter of 2013 (3,509 bbl/d). This reflected lower NGL sales due to a combination of leaner wells and processing changes at both East and West Edson as well as the disposition of non-core heavy oil properties completed during the fourth quarter of 2014 and natural declines on the Company's Mannville heavy oil property.

Financial Highlights

  • Perpetual recorded funds flow of $17.3 million ( $0.12 per share) for the fourth quarter of 2014, up 33 percent from the same period in 2013 ( $13.0 million ), reflecting increased year-over-year production as well as stronger natural gas prices compared to the fourth quarter of 2013.
  • Perpetual's average natural gas price, before derivatives, for the fourth quarter of 2014 was $3.96 /Mcf, up 18 percent from $3.37 /Mcf in the fourth quarter of 2013, consistent with the increase in AECO market prices year over year. Inclusive of $2.7 million in realized gains related to natural gas risk management contracts, Perpetual's realized gas price, including derivatives, for the fourth quarter was $4.16 /Mcf, 15 percent higher than the prior year's fourth quarter.
  • Perpetual's oil and NGL price, before derivatives, of $59.77 /bbl was nine percent lower than the prior year's fourth quarter ( $65.35 /bbl), directionally reflecting the severe drop in West Texas Intermediate ("WTI") crude oil prices to average US$73.15 /bbl (Q4 2013 - US$97.46 /bbl) during the fourth quarter of 2014. The impact of the drop in the WTI benchmark price was diminished somewhat by the tightening of the Western Canadian Select heavy oil differential and the drop in the $Cdn/$US dollar exchange rate.  Risk management strategies resulted in hedging gains of $1.6 million related to crude oil contracts, which were reflected in an average realized price, including derivatives, of $64.39 /bbl, two percent lower than the fourth quarter of 2013 ( $65.88 /bbl).
  • Primarily utilizing remaining proceeds from the senior notes issued during the third quarter of 2014, the Corporation redeemed $25.0 million of its 7.00% Convertible Debentures on December 31 , 2014.  The balance of the 7.00% Convertible Debentures ( $34.9 million ) have a maturity date of December 31, 2015 .
  • On November 5, 2014 , Perpetual's borrowing base increased to $105 million as a result of reserve additions driven by drilling activities at East Edson , despite adjustments related to the monetization of additional GOB royalty credits and the disposition of non-core heavy oil properties.
  • A net loss of $18.3 million ( $0.12 per share) was recorded for the fourth quarter of 2014, including $21.4 million for an estimated net impairment loss on the Company's Birchwavy assets.  The impairment resulted primarily from the decrease in crude oil and natural gas forecast prices at year end 2014.

2014 ANNUAL HIGHLIGHTS

Capital Spending and Property Dispositions

  • Exploration and development expenditures of $115.8 million during 2014 included $81.1 million allocated to liquids-rich natural gas development activities in the Corporation's West Central district ( Greater Edson area), $24.5 million for heavy oil development at Mannville and $10.2 million on shallow gas optimization projects.
  • Drilling operations included 11 (5.5 net) operated wells and two (0.1 net) non-operated wells drilled in West Edson ; 15 (15.0 net) wells drilled in East Edson , including 13 (13.0 net) wells financed from the partner's escrow account; and 20 (17.8 net) horizontal heavy oil wells on the Company's Mannville property.
  • Development activities also included expansion of the West Edson facility to 60 MMcf/d gross (30 MMcf/d net); initial construction costs for the new East Edson gas plant; recompletion, workover and optimization projects on the Company's shallow gas assets; the conversion of seven wells to injection and expenditures for related pipelines and facilities on the startup of the Mannville waterflood pilot project; and initial spending for a cyclic heat stimulation test as phase 1 of the LEAD pilot project for bitumen extraction at Panny.
  • Dispositions, net of acquisitions, of $70.4 million included net proceeds of $47.0 million under the East Edson JV on the disposition of an overriding royalty interest; $21.4 million on the disposition of non-core Mannville heavy oil assets and $3.0 million received on the sale of undeveloped land.  Offsetting property dispositions were acquisitions of $1.0 million , primarily related to additional land purchases in the Greater Edson area.
  • Perpetual closed two transactions in 2014 which effectively monetized the majority of its future GOB royalty credits associated with certain shut-in properties in northeast Alberta for net proceeds of $21.3 million .  In exchange for the proceeds, Perpetual makes monthly payments to the purchaser, which are based on the gas over bitumen formula set out in the Alberta Gas Royalty Regulations, effectively flowing through proceeds which result from GOB royalty credits.

Production Highlights

  • Total production increased ten percent to 20,554 boe/d in 2014 (2013 - 18,696 boe/d) reflecting new production from the 2014 drilling program which continued to be focused on the Company's liquid-rich properties in West Central and heavy oil properties in Mannville as well as highly efficient workover, recompletion and facility optimization projects mitigating shallow gas production declines in eastern Alberta .
  • Natural gas production of 102.7 MMcf/d increased 16 percent from 88.9 MMcf/d in 2013, primarily due to production growth at West Edson , which averaged 25.6 MMcf/d (2013 - 10.8 MMcf/d) and East Edson , which averaged 17.7 MMcf/d (2013 - 14.3 MMcf/d).  Increases in higher heat content deep basin gas production at East and West Edson more than offset year over year declines in gas production from Perpetual's eastern Alberta assets, which was reduced to just five percent by highly profitable shallow gas optimization projects.
  • Oil and NGL production of 3,443 bbl/d was 11 percent lower than 2013 (3,860 bbl/d).  Crude oil production of 2,906 bbl/d (2013 – 3,205 bbl/d) reflected a reduced Mannville heavy oil drilling program compared to 2013 as well as the impact of the non-core heavy oil disposition completed in the fourth quarter.  NGL production of 537 bbl/d (2013 – 655 bbl/d) reflected lower average NGL yields on wells drilled at West Edson as well as a change in processing arrangements at both East and West Edson which results in previously reported liquids now included as part of higher heat content natural gas sales.
  • Deep basin resource-style assets in West Central Alberta contributed 7,649 boe/d of natural gas and associated liquids, representing 37 percent of total production in 2014, up from 26 percent in 2013. High netback Mannville heavy oil production of 2,860 boe/d comprised 14 percent of total production in 2014.

Financial Highlights

  • Revenue of $262.8 million was 31 percent higher than 2013 ( $201.3 million ) reflecting increased production and higher average commodity prices in 2014.
  • Realized natural gas prices, including derivatives, of $4.36 /Mcf in 2014 increased 24 percent from $3.53 /Mcf in 2013, reflecting a 40% increase in AECO Monthly Index prices year-over-year, partially offset by losses realized on gas price hedging contracts during 2014.  Due to the higher percentage of liquids-rich gas production and processing changes in both West and East Edson , Perpetual's heat content averaged 1.13 GJ/Mcf in 2014 relative to 1.10 GJ/Mcf in 2013.
  • Oil and NGL prices, including derivatives, of $71.82 /bbl increased eight percent in 2014 due to strong WTI prices during the first half of 2014 which, along with a narrowing of WCS differentials, offset the effect of oil and NGL price declines realized in the fourth quarter.  Perpetual's realized oil and NGL price, including derivatives, was four percent lower than the price before derivatives in 2014, primarily due to hedging losses recorded on financial WTI price contracts during the first three quarters of 2014, which were not fully overcome by gains realized during the fourth quarter of 2014 as oil prices declined.
  • Royalty expense of $32.0 million in 2014 represented a combined royalty rate of 12.2 percent compared to 9.4 percent in 2013.  An increase in freehold and overriding royalty expense reflected new royalties payable pursuant to the East Edson JV, which entitle the partner to overriding royalties based on a maximum of 5.6 MMcf/d of natural gas from the East Edson property plus oil and associated NGL on a monthly basis beginning July 1 , 2014.  Excluding overriding royalty payments related to the East Edson JV, the combined royalty rate for 2014 was 10.2 percent, which was still higher than in 2013 due to higher Alberta gas reference prices and higher oil royalties related to production on freehold lands and wells transitioning from incentive periods.
  • Operating costs decreased another six percent in 2014 to $10.41 /boe, down from $11.05 /boe in 2013, with absolute savings realized in most areas of operations. Infrastructure expansion and enhancements at West Edson , and the re-routing of the majority of East Edson production from a third-party deep cut facility to utilize the Company's minority interest in the lower cost Rosevear plant, resulted in decreased processing fees paid to third parties and increased efficiency on a unit-of-production basis.
  • Operating netbacks increased 15 percent to $17.44 /boe (2013 - $15.23 /boe) with higher commodity prices and lower operating costs more than offsetting higher transportation costs as well as increased royalties.
  • Funds flow of $81.4 million ( $0.55 per share) in 2014 increased 39 percent from $58.5 million ( $0.39 per share) in 2013 as a result of increased production, stronger crude oil and natural gas prices, and higher operating netbacks in 2014.
  • Perpetual issued $125 million in 8.75 percent senior notes during the third quarter of 2014 with the proceeds utilized for the early redemption of $100 million of 7.25 percent Convertible Debentures in August 2014 and $25 million of 7.00 percent Convertible Debentures on December 31 , 2014.  The issue of senior notes bolstered Perpetual's financial flexibility by extending its long-term debt beyond 2018.
  • Total net debt decreased by 12 percent ( $45.2 million ) from $377.0 million on December 31, 2013 to $331.7 million at December 31, 2014 . The reduction in net debt resulted from 2014 funds flow, combined with proceeds received on dispositions, the monetization of GOB royalty credits, and Perpetual's escrow funds related to the East Edson JV, which, in total, exceeded 2014 capital expenditures.  The ratio of net debt to trailing 12 months funds flow improved by 36 percent from year end 2013 to a ratio of 4.1 to 1 at December 31, 2014 .
  • The Corporation recorded net income of $3.4 million ( $0.02 per share) compared to $7.6 million ( $0.05 per share) in 2013.

2015 OUTLOOK

In 2015, Perpetual is focused on five strategic priorities:

  • Grow greater Edson liquids-rich gas production, cash flow, inventory, reserves and value;
  • Optimize value of Mannville heavy oil;
  • Refine elements of production growth strategy for 2017 to 2020;
  • Maximize value of shallow gas; and
  • Reduce debt and improve debt/cash flow ratio.

In light of current weakness and uncertainty in commodity prices, Perpetual's Board of Directors has approved a first quarter capital expenditure budget of $45 million . Nearly $42 million will be directed to the drilling of six wells (4.5 net) in west central Alberta , with three (1.5 net) at West Edson and three (3.0 net) at East Edson , coupled with the East Edson plant construction activities. All heavy oil drilling has been deferred until oil prices recover, although $1.3 million will be expended on advancing the Mannville waterflood. Strategic spending at Panny to advance the LEAD pilot project has been reduced to include only capital required to drill two (2.0 net) observation wells associated with the pilot scheme, estimated at $1.2 million .

Capital activity for the remainder of the year will be assessed as the year progresses with the intention that spending will be largely funded from funds flow and available bank indebtedness. The reduction in drilling in first quarter 2015 will not materially impact 2015 gas production as the wells drilled to date have generally exceeded the type curves and provide the same production capability as originally budgeted. Further, variations in capital spending for the final three quarters of 2015 are not expected to materially affect average production or annual funds flow.

Perpetual has commodity price contracts in place for both crude oil and natural gas to protect a base level of cash flow.  Natural gas contracts were entered into to provide downside protection on revenue, primarily through the summer months, with physical and financial contracts in place for 2015 on an average of close to 68,400 GJ/d at an average price of $2.63 /GJ. Crude oil contracts for 2015 on 1,000 bbls/d include costless collars protecting a WTI floor price of Cdn$87.50 /bbl with an average ceiling of Cdn$95.50 /bbl, as well as financial contracts which fix the basis differential between WTI and Western Canadian Select trading hubs at an average of US$16.88 /bbl.

Incorporating the assumptions and commodity price contracts outlined above, the following table shows Perpetual's estimated 2015 funds flow using various commodity prices:

Projected 2015 funds flow (2) ($millions)

AECO gas price ($/GJ) (1)

WTI price (US$/bbl) (1)

$2.50

$3.00

$3.50

$4.00

$4.50

$45.00

4.7

13.8

22.9

32.1

41.2

$50.00

6.8

15.9

25.1

34.2

43.3

$55.00

8.9

18.0

27.2

36.3

45.4

$60.00

11.0

20.1

29.3

38.4

47.5

$65.00

13.1

22.2

31.4

40.5

49.6

(1)

The current settled and forward average AECO and WTI prices for 2015 as of March 4, 2015 were $2.69 per GJ and US$55.69 per bbl, respectively.

(2)

Funds flow is a non-GAAP measures. Please refer to "Non-GAAP Measures" below.

Amendment to Credit Facility

The Corporation's credit facility is with a syndicate of Canadian chartered banks. As at December 31, 2014 total availability under the facility was $105 million .  The credit facility includes covenants with respect to debt and trailing funds flow ratios.  The Corporation was in compliance with the lender's covenants at December 31, 2014 . On March 5, 2015 , the Corporation's lenders agreed to revise financial covenants based on prevailing low commodity prices at the end of 2014 and uncertainty surrounding forecast commodity prices into 2016.  Based on internal 2015 and 2016 financial and operating forecasts, Perpetual expects to be in compliance with the lender's new covenants. The next semi-annual redetermination of the Corporation's borrowing base will occur on or before April 30, 2015 .

Financial and Operating Highlights

THREE MONTHS

Ended December 31

YEAR ENDED

December 31,

($Cdn thousands except volume and per share amounts)

2014

2013

Change

2014

2013

Change

Financial

Oil and natural gas revenue

62,562

49,075

27%

262,790

201,294

31%

Funds flow (1)

17,316

12,998

33%

81,395

58,468

39%

Per share (1) (2)

0.12

0.09

33%

0.55

0.39

41%

Net earnings (loss)

(18,273)

(13,745)

(33%)

3,366

7,620

(56%)

Per share (2)

(0.12)

(0.09)

(33%)

0.02

0.05

(60%)

Total assets

750,602

742,288

1%

750,602

742,288

1%

Net bank debt outstanding (1)

21,867

67,201

(67%)

21,867

67,201

(67%)

Senior notes, at principal amount

275,000

150,000

83%

275,000

150,000

83%

Convertible debentures, at principal amount

34,878

159,779

(78%)

34,878

159,779

(78%)

Total net debt (1)

331,745

376,980

(12%)

331,745

376,980

(12%)

Capital expenditures

Exploration and development (3)

26,018

24,518

6%

116,457

96,684

20%

Dispositions, net of Acquisitions

(20,595)

(483)

4164%

(70,351)

(70,840)

(1%)

Interest in Warwick Gas Storage

-

-

-

-

19,129

(100%)

Other

84

2

4100%

614

120

412%

Net capital expenditures

5,507

24,037

(77%)

46,720

45,093

4%

Common shares outstanding (thousands)

End of period

150,077

148,490

1%

150,077

148,490

1%

Weighted average

149,084

148,144

1%

149,084

148,144

1%

Operating

Average production

Natural gas (MMcf/d) (4)

122.5

90.3

36%

102.7

88.9

16%

Oil and NGL (bbl/d) (4)

3,262

3,509

(7%)

3,443

3,860

(11%)

Total (boe/d)

23,685

18,559

28%

20,554

18,696

10%

Average prices

Natural gas, before derivatives ($/Mcf)

3.96

3.37

18%

4.50

3.26

38%

Natural gas, including derivatives ($/Mcf)

4.16

3.62

15%

4.36

3.53

24%

Oil and NGL, before derivatives ($/bbl)

59.77

65.35

(9%)

75.01

67.65

11%

Oil and NGL, including derivatives ($/bbl)

64.39

65.88

(2%)

71.82

66.48

8%

Barrel of oil equivalent, including derivatives ($/boe)

30.40

30.09

1%

33.81

30.56

11%

Drilling (wells drilled gross/net) (5)

Gas

11/10.0

4/2.0

29/20.9

6/3.0

Oil

-

5/5.0

20/17.8

37/35.7

Total

11/10.0

9/7.0

49/38.7

43/38.7

Success rate (%)

100/100

100/100

100/100

100/100

(1)

These are non-GAAP measure. Please refer to "Non-GAAP Measures" below.

(2)

Based on weighted average basic common shares outstanding for the period.

(3)

Exploration and development costs include geological and geophysical expenditures.

(4)

Production amounts are based on the Corporation's interest before royalty expense.

(5)

Wells drilled includes gas wells drilled as part of the East Edson JV

Forward-Looking Information and Statements

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations and including the information contained under the heading "2015 Outlook" may constitute forward-looking information and statements under applicable securities laws. The forward-looking information and statements includes, without limitation, statements regarding capital expenditure levels for 2015, prospective drilling activities; forecast production, production type, operations, funds flows, and timing thereof; forecast and realized commodity prices; expected funding, allocation and timing of capital expenditures; expected compliance with credit facility covenants in 2015 and 2016; projected use of funds flow and anticipated funds flow; planned drilling and development and the results thereof; expected dispositions, anticipated proceeds therefrom and the use of proceeds therefrom; and commodity prices. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information and statements contained in this press release, which assumptions are based on management analysis of historical trends, experience, current conditions, and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward looking information and statements contained in this press release. Undue reliance should not be placed on forward-looking information and statements, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2014 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website ( www.sedar.com ) and at Perpetual's website ( www.perpetualenergyinc.com ). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities laws.

Volume Conversions

Barrel of oil equivalent ("boe") may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ("NI 51-101"), a conversion ratio for natural gas of 6 Mcf:1bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion on a 6 Mcf:1 bbl basis may be misleading as an indicator of value as the value ratio between natural gas and crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl.

Non-GAAP Measures

This news release contains financial measures that may not be calculated in accordance with generally accepted accounting principles in Canada ("GAAP"). Readers are referred to advisories and further discussion on non-GAAP measures contained in the "Significant Accounting Policies and non-GAAP Measures" section of management's discussion and analysis.

About Perpetual

Perpetual Energy Inc. is a Canadian energy company with a spectrum of resource-style opportunities spanning heavy oil, NGL and bitumen along with a large base of shallow gas assets. Perpetual's shares and convertible debentures are listed on the Toronto Stock Exchange under the symbol "PMT", "PMT.DB.D" and "PMT.DB.E", respectively. Further information with respect to Perpetual can be found at its website at www.perpetualenergyinc.com .

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

SOURCE Perpetual Energy Inc.

Canyon Services Group Inc. reports record fourth quarter, 2015 capital expenditure update and maintains dividend

CALGARY , March 5, 2015 /CNW/ - Canyon Services Group Inc. ("Canyon" or the "Company") is pleased to announce its fourth quarter 2014 results.  The following results should be read in conjunction with the Management's Discussion and Analysis, the audited consolidated financial statements and notes of Canyon Services Group Inc. for the year ended December 31, 2014 and should also be read in conjunction with the audited consolidated financial statements and Annual Information Form for the year ended December 31, 2013, which are available on SEDAR at www.sedar.com .

The current quarter includes the results of Canyon's pressure pumping business as well as the results of Fraction Energy Services Ltd., ("Fraction") a leading provider of fracturing fluid management, including water sourcing, transfer, wellsite storage, fluid heating, flowback transfer and produced water storage services, which was acquired by Canyon effective July 1, 2014 .

HIGHLIGHTS

The operating and financial highlights for the three and twelve months ended December 31, 2014 are summarized as follows:

  • Q4 2014 was very active for Canyon, with consolidated revenues increasing by 81% to $188.3 million compared to $104.2 million in Q4 2013.  For the year ended December 31, 2014 , consolidated revenues almost doubled to $591.0 million , an increase of 97% over the $299.6 million recorded in the 2013 year.
  • As at December 31, 2014 , Canyon had available bank credit facilities combined with positive working capital totaling $92 million .  As a result, Canyon remains in a very strong financial position and is well positioned to withstand the dramatically reduced industry activity levels expected in 2015 and to fund potential attractive investment opportunities.
  • The increased activity and the inclusion of Fraction resulted in a four-fold increase in consolidated EBITDA before share based payments to $45.6 million in the current quarter from $11.0 million in Q4 2013.  Consolidated income and comprehensive income increased to $22.3 million in Q4 2014 from $0.4 million in Q4 2013.  For the year ended December 31, 2014 consolidated EBITDA before share based payments increased to $121.5 million from $32.5 million in 2013, while consolidated income and comprehensive income significantly increased to $49.1 million from a loss and comprehensive loss of $4.4 million for the comparable 2013 period.
  • Effective July 1, 2014 , Canyon acquired Fraction, a leading provider of water and fracturing fluid logistics, containment, transfer and storage for the oil and gas industry in Northwest Alberta and Northeast British Columbia.  In Q4 2014, Fraction contributed $12.9 million to consolidated revenue and $3.3 million to consolidated EBITDA before share-based payments expense.  Water access restrictions, enacted in the third quarter but carrying on into the fourth quarter, impacted fourth quarter results for Fraction.  These restrictions were lifted late in the fourth quarter, resulting in increased water transfer and storage tank utilization in 2015 to date.
  • In 2014, Canyon added 30,000 Hydraulic Horsepower ("HHP") to its equipment fleet, including 20,000 HHP purchased from a competitor in March and 10,000 HHP of newly constructed equipment added in Q4 2014.  These additions brought Canyon's pressure pumping equipment capacity to 255,500 HHP as at December 31, 2014 .
  • Canyon's previously announced 2015 capital program totaling $63 million has been significantly reduced in response to anticipated lower industry activity levels in 2015.  Canyon's 2015 capital program is now estimated at approximately $12 million , mostly for maintenance capital, which combined with a carryover of about $8 million to complete the 2014 program results in total capital expenditures of approximately $20 million for 2015.
  • On December 18, 2014 , Canyon declared a quarterly dividend of $0.15 per common share, or $10.3 million , which was paid to shareholders on January 26, 2015 .

INDUSTRY COMMENTARY & 2015 OUTLOOK

To date in 2015, overall Canadian oilfield industry activity levels have rapidly declined in response to the ongoing dramatic drop in oil and natural gas prices since the summer of 2014.  As our customers adjust to lower commodity prices, they have reduced or deferred drilling and completions' activities, and have further high-graded their projects.  The deterioration of oil and natural gas prices over the last 8 months has significantly altered industry and Canyon's expectations of activity levels and job pricing for 2015.  Leading indicators such as drilling rig utilization in the WCSB is down about 33% over the first half of Q1 2015 compared to the same period in Q1 2014.  As expected, declining activity levels lead to pricing pressure and this is already evident in Q1 2015, with the pricing gains achieved throughout 2014 already eroding margins.  To soften the impact on 2015 operating margins from lower job pricing, Canyon continues to implement measures to reduce our operating costs.  Our suppliers have also been very cooperative and have been lowering some of our cost of services, including proppants, diesel, nitrogen and third party trucking costs.  Although the Company has very low debt levels and an industry‑leading cost structure, we are not immune to what will likely be the worst year‑over‑year drilling and completions activity reduction in decades.  Canyon will take a defensive stance and will implement cost saving initiatives such as reducing compensation levels for staff, management and the board of directors, to reduce the negative impact reduced pricing and activity levels are expected to have on operating margins and cash flow.  We believe that Canyon has never been better positioned to not only navigate through this downturn, but to also grow our market share.  The key to a successful emergence from this downturn will be keeping the impact of cost saving initiatives on staff to the minimum so that our valued employees are able to stay focused on adding value for our customers and shareholders.

Despite sharply declining oilfield activity levels and pricing pressure, Canyon has actually remained relatively active in both our pressure pumping and fluid management divisions in Q1 2015.  These relationships will help to reduce margin pressure by increasing efficiencies in our pad-based, 24 hour work programs resulting in improved value for our customers.  With the recent acquisition of the fluid management business, Canyon is able to bundle fracturing and water services for the customer thereby avoiding well completion delays.  To date in 2015, our fluid management business has had a strong start to the year.  In addition, the increased demand for 24 hour operations by our customers presents the opportunity for us to improve operating cost efficiency.  Canyon expects to remain active for the remainder of Q1 2015 as we are essentially fully booked until break up 2015.

LNG driven activity levels and timing remain a big question in this industry.  Although Canada is still several years from seeing the first LNG exports, visibility has sharpened, overall risks have been marginalized and upstream momentum has been building.  The Federal Government's recent announcement to accelerate the capital cost allowance for certain LNG based expenditures combined with British Columbia's announcement detailing the proposed LNG tax structure have been viewed favourably by the energy industry.  Numerous projects have been proposed, representing approximately 15 – 20 billion cubic feet per day in combined export capacity.  Project approvals were granted in 2013, while site preparation and front-end engineering were initiated for some projects.  We continue to anticipate a positive final investment decision announcement for a west coast of British Columba project in 2015.  The timing of meaningful ramp‑up in activity remains uncertain.

As a result of our strong balance sheet and our lean cost structure, Canyon's strategy remains essentially unchanged.  Our goal is to build a Canadian service provider that can succeed and grow over the long term and provide superior return on invested capital to our investors by reducing finding and development costs for our customers.  In the short-term, with our strong balance sheet and prudent fiscal management, we can endure the approaching period of reduced oilfield services activity levels brought on by the recent commodity price degradation without having to make significant adjustments to how we implement our strategy.

During this difficult operating period for the industry, our strong financial position also allows us to seek out attractive investment opportunities.  Canyon will actively screen, evaluate and pursue attractive oilfield acquisition opportunities that will add both long-term value on a per share basis and enhance our relative competitive position with customers.  Our plan is to continue to grow Canyon's operating assets over the next five years, primarily to service the anticipated demand for pressure-pumping services in Western Canada.  We are actively working to cement relationships with top-tier multinational customers and continuing to grow in activity and reputation in the region's premier unconventional plays.  Growth in our market share in Northwest Alberta and Northeast British Columbia will be complemented by pursuit of attractive opportunities in the Cardium, Bakken and Lower Shaunavon plays. We continue to believe that Western Canada is still a highly attractive pressure pumping market as it continues to hold significant growth potential and offers superior supply-demand fundamentals to many other international markets.

Canyon will continue our pursuit to continue building a high-quality, growing service provider with a robust organization that can accommodate much higher revenue.  This creates the foundation for rapidly growing revenue, operating margins and EBITDA on a per share basis.

OVERVIEW OF FOURTH QUARTER AND YEAR ENDED 2014

000's except per share, job amounts and
hydraulic pumping capacity
(Unaudited)

Three Months Ended
December 31

Year Ended
December 31

2014

2013

2012

2014

2013

2012

Consolidated revenues

$188,265

$104,227

$84,809

$591,022

$299,614

$353,119

Profit (loss) and comprehensive income (loss)

$22,280

$377

$7,146

$49,094

$(4,375)

$54,409

Per share-basic

$0.32

$0.01

$0.12

$0.75

$(0.07)

$0.89

Per share-diluted

$0.32

$0.01

$0.11

$0.74

$(0.07)

$0.87

EBITDA before share-based payments (1)

$45,576

$11,026

$18,814

$121,478

$32,496

$107,774

Funds from operations (1)

$38,084

$17,574

$18,501

$103,819

$38,716

$95,535

Adjusted profit (loss) and comprehensive income (loss) (1)

$24,870

$1,690

$7,836

$56,120

$(45)

$55,584

Adjusted per share-basic (1)

$0.36

$0.03

$0.12

$0.85

$(0.00)

$0.91

Adjusted per share-diluted (1)

$0.36

$0.03

$0.11

$0.84

$(0.00)

$0.89

Total jobs completed (2)

818

654

489

2,942

1,828

2,198

Consolidated average revenue per job (2)

$215,784

$159,835

$176,162

$192,004

$164,529

$161,668

Average fracturing revenue per job

$318,705

$225,675

$280,671

$269,894

$232,460

$240,369

Hydraulic Pumping Capacity:

Average HHP

245,500

225,500

225,500

240,500

225,500

215,000

Exit HHP

255,500

225,500

225,500

255,500

225,500

225,500

Capital expenditures

$36,830

$7,442

$5,419

$112,677

$14,840

$69,940

000's except per share amounts

(Unaudited)

As at
December 31,
2014

As at
December 31,
2013

As at
December 31,
2012

Cash and cash equivalents

$20,613

$21,308

$22,584

Working capital

$21,880

$41,730

$56,245

Total long-term financial liabilities

$36,193

$3,096

$3,475

Total assets

$638,770

$402,707

$406,113

Cash dividends declared per share

$0.60

$0.60

$0.60

Note (1):

See Non-GAAP Measures.

Note (2):

Includes all jobs from each service line, specifically hydraulic fracturing; coiled tubing; nitrogen fracturing;
acidizing and remedial cementing.

The current quarter and the twelve months ended December 31, 2014 includes the results of Canyon's pressure pumping business.  The results of Fraction Energy Services Ltd., ("Fraction") are included for the second half of 2014.  Fraction was acquired by Canyon effective July 1, 2014 and is a leading provider of fracturing fluid management, including water sourcing, transfer, wellsite storage, fluid heating, flowback transfer and produced water storage services.

Continuing on from the record previous quarter, Q4 2014 was very busy for Canyon, with consolidated revenues increasing by 81% to $188.3 million compared to $104.2 million in Q4 2013.  For the year ended December 31, 2014 , consolidated revenues almost doubled to $591.0 million , an increase of 97% over the $299.6 million recorded in the 2013 year.  The Company did experience an 8% sequential decline in consolidated revenues in Q4 2014 over Q3 2014.  This was a result of redeploying equipment from a major customer to other customers, non-typical operational and weather delays, as well as the holiday break.

Consolidated EBITDA before share-based payments (see Non-GAAP Measures) increased over 300% to $45.6 million in Q4 2014 from $11.0 million in Q4 2013.  For the year ended December 31, 2014 , consolidated EBITDA before share-based payments expense increased almost 300% to $121.5 million from $32.5 million in 2013.

The increased activity and revenues in 2014 combined with Canyon's considerable operating leverage in its pressure pumping business and the inclusion of Fraction resulted in a significant improvement in profitability, with consolidated income and comprehensive income increasing to $22.3 million in Q4 2014 compared to $0.4 million in Q4 2013.  Adjusted consolidated income and comprehensive income (see Non-GAAP Measures) for Q4 2014 increased to $24.9 million from $1.7 million in Q4 2013.  For the year ended December 31, 2014 consolidated income and comprehensive income increased significantly to $49.1 million from a consolidated loss and comprehensive loss of $4.4 million for 2013.  Adjusted consolidated income and comprehensive income (see Non-GAAP Measures) increased to $56.1 million from a consolidated loss and comprehensive loss of $45 thousand in 2013.

Pressure Pumping Services

The fourth quarter was very strong for Canyon's pressure pumping business, with jobs completed and revenues earned increasing by 25% and 68%, respectively, compared to Q4 2013.  Jobs completed did not increase proportionately with the percentage revenue increase due to the growing trend for larger job sizes as discussed below.  Pressure pumping revenues in the current quarter totaled $175.4 million from 818 jobs completed compared to $104.2 million from 654 jobs in the comparable quarter of 2013.  For the year ended December 31, 2014 , pressure pumping revenues increased by 88% to $561.9 million compared to $299.6 million in 2013, while jobs completed increased by 61% to 2,942 from 1,828 over the same year.  In 2014, Canyon added 30,000 Hydraulic Horsepower ("HHP") to its equipment fleet including 20,000 HHP purchased from a competitor in March and 10,000 HHP of newly constructed pumps delivered in Q4 2014.  These additions bring Canyon's equipment capacity to 255,500 HHP as at December 31, 2014 .

Canyon's equipment fleet was essentially fully utilized throughout most of 2014 due to higher industry activity in the year as well as the Company's ongoing sales initiatives which have resulted in increased market share with oil and gas exploration companies ("E&P Companies") operating in the deep basin.  Market share continues to expand in Southeast Saskatchewan and Southwest Manitoba.  In 2014, drilling activity across the Western Canadian Sedimentary Basin ("WCSB") increased by about 9% to an industry utilization rate of 46% from 42% in 2013.  Industry activity remained strong throughout the second half of 2014 despite the significant decline in commodity prices since July.  Our customers' activity levels were buoyed by strong commodity prices in the first half of the year, improved access to capital markets to fund capital programs, as well as ongoing LNG-related reserve delineation drilling in Northeast British Columbia.  Also contributing to the higher pressure pumping activity in the year were changing well designs resulting in increased fracturing intensity on a per well basis in the form of more fractures per wellbore and/or larger fracture designs.  One of the main predictors of service intensity for pressure pumping is the average total length in metres per well.  The industry experienced an increase of 11% in the total metres per well drilled in 2014 over 2013.  In addition, increased proppant usage per stage has increased dramatically in 2014 with fourth quarter total proppant volumes pumped by Canyon increasing by 91% compared to Q4 2013, and by 111% for the year ended December 31, 2014 compared to 2013.  The growing trend by customers to use more proppant per stage and in particular more expensive "Ottawa White" sand rather than domestic sand has also contributed to larger job sizes reflected in the increased revenue per job.  Therefore, Canyon's average fracturing revenue per job increased by 41% to $318,705 in Q4 2014 from $225,675 in Q4 2013 mostly due to the larger job sizes.  Overall, job pricing and cost recovery had only a modest impact on revenue per job and revenues in Q4 2014 as pricing improved by approximately 10% from the beginning of the year.

Pressure pumping cash flow and profitability remains highly levered to changes in revenue due to the fixed cost nature of the business.  The increased activity and revenues in the year led to significantly improved margins in Q4 2014 compared to the comparable quarter of 2013.  In Q4 2014, EBITDA before share-based payments expense from pressure pumping was $44.0 million , or 25% of revenues, compared to $12.8 million or 12% of revenues in the comparable 2013 quarter.  The increased activity has also significantly increased EBITDA before share-based payments expense from pressure pumping to $119.0 million , or 21% of revenues, for the year ended December 31, 2014 from $38.4 million or 13% of revenues for 2013.

In 2014, Canyon increased its pressure pumping field staff by approximately 20% from the beginning of the year.  In addition to hiring new staff, we continued to increase our training and staff development and upgraded business systems throughout the organization until late in 2014.  Unfortunately, with the significant decline in commodity prices and the expected pullback in E&P companies' capital programs in 2015, Canyon began implementing cost cutting measures in Q4 2014 including a slow down of hiring new staff.

Fluid Management Services

Fraction was acquired by Canyon effective July 1, 2014 and continues as a wholly-owned and independent operating subsidiary.  Fraction is a leading provider of fracturing fluid logistics, containment, transfer and storage for the oil and gas industry in Northwest Alberta and Northeast British Columbia.  The acquisition of Fraction complements Canyon's current offering of services to our customers.

For the three months ended December 31, 2014 Fraction contributed $12.9 million in revenue and $3.3 million in EBITDA before share-based payments expense (see Non-GAAP Measures).  For the six month period, the division contributed $29.1 million in revenue and $9.5 million in EBITDA before share-based payments (see Non-GAAP Measures).

As previously reported, water access restrictions in the northern regions of the WCSB were imposed in the latter half of the third quarter and continued to impact water transfer and fluid logistics revenues during the fourth quarter.  As a result, there were a limited number of long distance water transfer projects in the region limiting Fraction's water transfer projects during the quarter to lease site fluid management. Storage tank rental revenues were also lower in Q4 2014 compared to the prior quarter due to lower activity by certain customers in response to the declining commodity prices as well as the deferral of a final investment decision by an LNG project sponsor.

The water access restrictions were lifted in December 2014 allowing Fraction to gain larger fluid transfer and logistics projects late in Q4 2014 and has resulted in a strong start to Q1 2015.  In addition, storage tank rental revenues have rebounded in Q1 2015 to date with higher utilization rates of the division's tank fleet.  The division took delivery of its two Super Heater units, which were part of the 2014 capital program, in December 2014.  This has further enhanced Fraction's full service water management solutions and helped contribute to a strong start to Q1 2015.

2015 Capital Expenditure Budget Update

On November 6, 2014 in our Q3 press release and MD&A, Canyon reported a forecast 2015 capital expenditure budget of approximately $63 million .  This budget included both maintenance and growth capital for each of the pressure pumping and fluid management service lines.  Given the unexpected and significant decrease in oil and natural gas prices that has caused material cuts to our customers' drilling and completions budgets, Canyon has effectively suspended all growth capital expenditures.  Our revised 2015 capital expenditure budget will consist of approximately $12 million for maintenance capital and approximately $8 million for 2014 capital items that have experienced delays into the first half of 2015.  Canyon expects that our revised capital budget totaling $20 million will be funded from operating cash flow and existing banking facilities.

Dividend

The Board of Directors (the "Board") continuously reviews the long-term capital structure of the Company and its corresponding dividend policy each fiscal quarter.  The Board sets a dividend rate that it believes will be sustainable over the long-term in the context of future cash flows and capital spending opportunities.  The Board has determined that the liquidity and financial capacity of the Company allow it to maintain the quarterly dividend at the current rate of $0.15 per common share per quarter.

NON-GAAP MEASURES

The Company's Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"). Certain measures in this document do not have any standardized meaning as prescribed by IFRS and are considered NON-GAAP measures.

EBITDA before share-based payments, funds from operations, adjusted profit (loss) and comprehensive income (loss) and adjusted per share amounts are not recognized measures under IFRS.  Management believes that in addition to profit (loss) and comprehensive income (loss), EBITDA before share-based payments, funds from operations and adjusted profit (loss) and comprehensive income (loss) are useful supplemental measures as they provide an indication of the results generated by the Company's business activities prior to consideration of how those activities are financed, amortized or taxed, as well as the cash generated by the Company's business activities without consideration of the timing of the monetization of non-cash working capital items.  Readers should be cautioned, however, that EBITDA before share-based payments, funds from operations and adjusted profit (loss) and comprehensive income (loss) and per share amounts should not be construed as an alternative to profit and comprehensive income determined in accordance with IFRS as an indicator of the Company's performance.  Canyon's method of calculating EBITDA before share-based payments, funds from operations and adjusted profit (loss) and comprehensive income (loss) may differ from other companies and accordingly, EBITDA before share-based payments, funds from operations and adjusted profit (loss) and comprehensive income (loss) may not be comparable to measures used by other companies.  Canyon calculates EBITDA before share-based payments as profit and comprehensive income for the year adjusted for depreciation and amortization, equity settled share-based payment transactions, gain or loss on sale of property and equipment, finance costs, foreign exchange gains and losses and income tax expense.  Adjusted profit (loss) and comprehensive income (loss) per share is calculated using the weighted average shares outstanding consistent with the calculation of earnings per share.  Reconciliations of these NON-GAAP measures to the most directly comparable IFRS measures are outlined below.

The Company describes revenue less cost of services as gross profit (loss).

EBITDA before share-based payments

000's
(Unaudited)

Three Months Ended
December 31

Year Ended
December 31

2014

2013

2014

2013

Profit (loss) and comprehensive income (loss)

$22,280

$377

$49,094

$(4,375)

Add (Deduct):

Depreciation and amortization

15,225

9,568

49,320

33,035

Finance costs

534

192

1,512

658

Foreign exchange (gain) loss

(155)

22

746

(171)

Share-based payment transactions

1,026

1,238

3,985

4,189

(Gain) Loss on sale of property and equipment

(127)

7

(315)

(5)

Income tax expense (recovery)

6,793

(378)

17,136

(835)

EBITDA before share-based payments

$45,576

$11,026

$121,478

$32,496

Funds from Operations

000's
(Unaudited)

Three Months Ended
December 31

Year Ended
December 31

2014

2013

2014

2013

Net cash from operating activities

$56,123

$22,777

$81,823

$51,450

Income tax (received) paid

(2,286)

-

(6,747)

5,135

Change in non-cash working capital

(8,644)

(11,965)

44,113

(24,576)

Less: current tax recovery (expense)

(7,109)

6,762

(15,370)

6,707

Funds from operations

$38,084

$17,574

$103,819

$38,716

Adjusted Profit (Loss) and Comprehensive Income (Loss)


000's
(Unaudited)

Three Months Ended
December 31

Year Ended
December 31

2014

2013

2014

2013

Profit (loss) and comprehensive income (loss)

$22,280

$377

$49,094

$(4,375)

Amortization expense on intangibles

1,564

75

3,041

141

Share-based payment transactions

1,026

1,238

3,985

4,189

Adjusted profit (loss) and comprehensive income (loss)

$24,870

$1,690

$56,120

$(45)

Adjusted per share-basic

$0.36

$0.03

$0.85

$(0.00)

Adjusted per share-diluted

$0.36

$0.03

$0.84

$(0.00)

QUARTERLY CONSOLIDATED STATEMENTS OF OPERATIONS

000's except per share amounts

(Unaudited)

Three Months Ended December 31

2014

2013

Revenues

$188,265

$104,227

Cost of services

(147,617)

(96,764)

Gross profit

40,648

7,463

Administrative expenses

(11,323)

(7,243)

Results from operating activities

29,325

220

Finance costs

(534)

(192)

Foreign exchange gain (loss)

155

(22)

Gain (loss) on sale of property and equipment

127

(7)

Profit (loss)  before income tax

29,073

(1)

Income tax (expense) recovery

(6,793)

378

Profit and comprehensive income

$22,280

$377

EBITDA before share-based payments (1)

$45,576

$11,026

Earnings  per share:

Basic

$0.32

$0.01

Diluted

$0.32

$0.01

Note (1):

See NON-GAAP Measures.

Pressure Pumping Services

000's except per share amounts

(Unaudited)

Three Months Ended December 31, 2014

2014

2013

Revenues

$175,398

$104,227

Cost of services

(137,997)

78.7%

(96,764)

92.8%

Gross profit

37,401

21.3%

7,463

7.2%

Administrative expenses

(5,888)

3.4%

(4,671)

4.5%

Results from operating activities

31,513

17.9%

2,792

2.7%

Add non-cash items:

Depreciation and amortization

12,057

6.9%

9,568

9.2%

Share-based payments expense

390

0.3%

462

0.4%

EBITDA before share-based payments (1)

$43,960

25.1%

$12,822

12.3%

Note (1):

See NON-GAAP Measures.

Revenues

Improved industry activity in 2014 led to Canyon having a very busy second half to the year and resulted in jobs completed and revenues earned by the pressure pumping division increasing by 25% and 68%, respectively, compared to Q4 2013.  Jobs completed did not increase proportionately with the percentage revenue increase due to the growing trend for larger job sizes as previously discussed.  Pressure pumping revenues in the current quarter totaled $175,398 from 818 jobs completed compared to $104,227 from 654 jobs in the comparable quarter of 2013  In Q4 2014, Canyon added 10,000 HHP of newly constructed equipment bringing Canyon's equipment capacity to 255,500 HHP as at December 31, 2014 .

Over 90% of Q4 2014 pressure pumping revenues were provided by hydraulic fracturing services with average fracturing revenue per job increasing by 41% to $318,705 from $225,675 in Q4 2013.  The increase in average fracturing revenue per job is more a function of larger job sizes than pricing increases due to a huge increase in product consumption, particularly proppants.  Fourth quarter total proppant volumes pumped by Canyon increased by 91% compared to Q4 2013, and by 111% for the year ended December 31, 2014 compared to 2013.  The growing trend by customers to use more proppant per stage and in particular more expensive "Ottawa" sand rather than domestic sand has also contributed to larger job sizes with resulting increased revenue per job.  On the other hand, Q4 2014 pricing averaged about 10% higher than at the beginning of the year and as a result only had a modest impact on revenue per job and revenues in the quarter.

Cost of services

Cost of services for the three months ended December 31, 2014 totaled $137,997 (2013: $96,764 ) and includes materials, products, transportation and repair costs of $96,631 (2013: $64,992 ), employee benefits expense of $29,836 (2013: $22,743 ), and depreciation of property and equipment of $11,530 (2013: $9,029 ).

Materials, products, transportation and repair costs increased by 49% to $96,631 in the current quarter from $64,992 in Q4 2013, due to the increased job count in the quarter and due to the increase in materials consumed per well, especially sand as previously discussed.  The increase in employee benefits expense is mainly due to field staff additions to support the higher activity levels, increased variable pay as a result of the higher activity and inflation in labour rates.  The increase in depreciation of property and equipment is due to additional depreciation pertaining to equipment introduced into service in late 2013 and in 2014, and accelerated depreciation relating to the replacement of a number of pump components.

Administrative expenses

Administrative expenses for the three months ended December 31, 2014 totaled $5,888 compared to $4,671 in Q4 2013 and include employee benefits expense, share-based payments expense, amortization of intangibles, depreciation of buildings and office equipment and other administrative expenses.  Share-based payments expense represents the value assigned to the granting of options and incentive-based units under the Company's Share Purchase Option Plan and Stock Based Compensation Plan respectively, using the Black-Scholes model.  For Q4 2014, $390 (Q4 2013 - $462 ) was charged to expenses and included in contributed surplus in respect of these two plans.

EBITDA Before Share-Based Payments (See NON-GAAP MEASURES)

Pressure pumping profitability remains highly levered to changes in revenue due to the fixed cost nature of the business and as a result the aforementioned 25% increase in the job count and the 68% increase in revenues led to significantly improved margins in Q4 2014 compared to the comparable quarter of 2013.  As a result, Q4 2014, EBITDA before share-based payments totaled $43,960 in the pressure pumping segment, or 25% of revenues compared to $12,822 , or 12% of revenues in Q4 2013.

Fluid Management Services

000's except per share amounts
(Unaudited)

Three Months Ended
December 31

2014

2013

Revenues

$12,867

$-

Cost of services

(9,620)

74.8%

-

-%

Gross profit

3,247

25.2%

-

-%

Administrative expenses

(3,094)

24.0%

-

-%

Results from operating activities

153

1.2%

-

-%

Add non-cash item:

Depreciation and amortization

3,168

24.6%

-

-%

EBITDA before share-based payments (1)

$3,321

25.8%

$-

-%

Note (1):

See NON-GAAP Measures.

Revenues

The water management services business, acquired effective July 1, 2014 , contributed $12,867 of revenues to Canyon in Q4 2014.  This compares to revenues of $16,256 recorded in the prior quarter.  As discussed above, water access restrictions in the northern regions of the WCSB were enacted in the latter half of the third quarter and continued to impact water transfer and fluid logistics revenues during the fourth quarter until December when the restrictions were lifted.

Cost of services

Cost of services for the three months ended December 31, 2014 totaled $9,620 and includes materials, products, transportation and repair costs of $4,681 , employee benefits expense of $3,274 , and depreciation of property and equipment of $1,665 .

Administrative expenses

Administrative expenses for the three months ended December 31, 2014 totaled $3,094 and includes employee benefits expense, depreciation of buildings and office equipment and amortization of intangibles and other administrative expenses.  Administrative expenses include $1,443 relating to the amortization of customer relationships and non-competition agreements pursuant to the acquisition of Fraction.

EBITDA Before Share-Based Payments (See NON-GAAP MEASURES)

Q4 2014 EBITDA before share-based payments totaled $3,321 in the fluid management services division, or 26% of revenues.

Corporate

000's except per share amounts
(Unaudited)

Three Months Ended
December 31

2014

2013

Revenues

$-

$-

Administrative expenses

(2,341)

(2,572)

Results from operating activities

(2,341)

(2,572)

Add non-cash item:

Share-based payments expense

636

776

EBITDA before share-based payments (1)

$(1,705)

$(1,796)

Note (1):

See NON-GAAP Measures.

This segment consists of costs incurred to operate a public company, including corporate management, head office costs, corporate share-based payment expenses and professional fees.

Administrative expenses

Administrative expenses for the three months ended December 31, 2014 totaled $2,341 compared to $2,572 in Q4 2013 and include employee benefits expense, share-based payments, and other head office administrative expenses.  The decrease in administrative expenses is mainly due to lower share-based payments expense.

Share-based payments expense represents the value assigned to the granting of options and incentive-based units under the Company's Share Purchase Option Plan and Stock Based Compensation Plan respectively, using the Black-Scholes model.  For Q4 2014, $636 (Q4 2013 - $667 ) was charged to expenses and included in contributed surplus in respect of these two plans.  In addition, obligations for payments under the Company's Deferred Share Unit Plan are accrued as share-based payments expense over the vesting period.  The accrued liability increases or decreases with fluctuations in the price of the Company's common shares, with a corresponding increase or decrease in the share-based payments expense.  In Q4 2014, share-based payments expense was nil (2013: $109 ) for the Company's Deferred Share Unit Plan to reflect changes in the price of the common shares of the Company.

Other Items – Quarterly Consolidated Statement of Operations

Finance costs

Finance costs include interest on bank indebtedness and finance lease obligations and totaled $534 in Q4 2014 (2013: $192 ).  The increase in finance costs is due to the increase in loans and borrowings used to partially fund the Company's 2014 capital program.

Income tax expense

At the expected combined income tax rate of 25%, the income before income tax for the three months ended December 31, 2014 of $29,073 would have resulted in an income tax expense of $7,268 , compared to the actual income tax expense of $6,793 .  The actual income tax expense was reduced by deductible expenses for income tax filing purposes exceeding those for financial accounting purposes.

EBITDA before share-based payments (See Non-GAAP Measures)

In Q4 2014, Canyon's increased activity resulted in consolidated EBITDA before share-based payments (see NON-GAAP MEASURES) of $45,576 .  The four-fold increase over the $11,026 recorded in the comparable 2013 quarter is due to the increase in activity and improved pricing as discussed above.

Income and comprehensive income and earnings per share

Income and comprehensive income increased significantly to $22,280 in Q4 2014 from $377 in Q4 2013, due to the increase in activity as previously discussed.

Basic and diluted earnings per share were $0.32 and $0.32 , respectively, for the three months ended December 31, 2014 compared to basic and diluted earnings per share of $0.01 for the comparable 2013 quarter.

YEAR-TO-DATE CONSOLIDATED STATEMENTS OF OPERATIONS

000's except per share amounts
(Unaudited)

Year Ended
December 31

2014

2013

Revenues

$591,022

$299,614

Cost of services

(486,261)

(279,805)

Gross profit

104,761

19,809

Administrative expenses

(36,588)

(24,537)

Results from operating activities

68,173

(4,728)

Finance costs

(1,512)

(658)

Foreign exchange (loss) gain

(746)

171

Gain on sale of property and equipment

315

5

Profit  (loss) before income tax

66,230

(5,210)

Income tax (expense) recovery

(17,136)

835

Profit (loss) and comprehensive income (loss)

$49,094

$(4,375)

EBITDA before share-based payments (1)

$121,478

$32,496

Earnings  (loss) per share:

Basic

$0.75

$(0.07)

Diluted

$0.74

$(0.07)

Note (1):

See Non-GAAP Measures.

Pressure Pumping Services

000's except per share amounts
(Unaudited)

Year Ended
December 31, 2014

2014

2013

Revenues

$561,899

$299,614

Cost of services

(467,006)

83.1%

(279,805)

93.4%

Gross profit

94,893

16.9%

19,809

6.6%

Administrative expenses

(21,417)

3.8%

(16,826)

5.6%

Results from operating activities

73,476

13.1%

2,983

1.0%

Add non-cash items:

Depreciation and amortization

43,338

7.7%

33,035

11.0%

Share-based payments expense

2,175

0.4%

2,391

0.8%

EBITDA before share-based payments (1)

$118,989

21.2%

$38,409

12.8%

Note (1):

See NON-GAAP Measures.

Revenues

Canyon's equipment fleet was essentially fully utilized throughout most of 2014 due to higher industry activity in the year as well as the Company's ongoing sales initiatives which have resulted in market share growth with companies operating in the deep basin as well as market share expansion in Southeast Saskatchewan and Southwest Manitoba.  Accordingly, for the year ended December 31, 2014 , pressure pumping revenues increased by 88% to $561.9 million compared to $299.6 million in 2013, while jobs completed increased by 61% to 2,942 from 1,828 over the same years.  Over 90% of 2014 pressure pumping revenues were provided by hydraulic fracturing services with average fracturing revenue per job increasing by 16% to $269,894 from $232,460 in 2013.  The increase in average fracturing revenue per job is more a function of larger job sizes than pricing increases due to an increase in product consumption by customers, particularly proppants.  Proppants pumped by Canyon in 2014 increased by 111% over the tonnages pumped in 2013. On the other hand,  over the course of the year, 2014 pricing increased by about 10% from the beginning of the year  In 2014, Canyon added 30,000 Hydraulic Horsepower ("HHP") to its equipment fleet including 20,000 HHP purchased from a competitor in March and 10,000 HHP of newly constructed equipment added in Q4 2014.

Cost of services

Cost of services for the twelve months ended December 31, 2014 totaled $467,006 (2013: $279,805 ) and includes materials, products, transportation and repair costs of $318,155 (2013: $174,965 ), employee benefits expense of $107,433 (2013: $73,539 ), and depreciation of property and equipment of $41,418 (2013: $31,301 ).

Materials, products, transportation and repair costs increased by 82% to $318,155 in the current period from $174,965 as the job count increased by 61% in the current year compared to the 2013 year.  The increase in materials, products, transportation and repair costs was greater than the percentage increase in the job count mainly due to the larger job sizes in 2014 characterized by higher quantities of materials consumed per well, especially sand, as previously discussed.  The increase in employee benefits expense is mainly due to field staff additions to support the higher activity levels, increased variable pay as a result of the higher activity and inflation in labour rates.  Canyon had 1,115 employees in its pressure pumping business as at December 31, 2014 compared to about 900 at the same time last year.  The increase in depreciation of property and equipment is due to additional depreciation pertaining to equipment introduced into service in late 2013 and in 2014 and accelerated depreciation relating to the replacement of pump components.

Administrative expenses

Administrative expenses for the twelve months ended December 31, 2014 totaled $21,417 (2013: $16,826 ) and include employee benefits expense, share-based payments expense, depreciation of buildings and office equipment and amortization of intangibles and other administrative expenses.  Employee benefits expense increased mainly due to staff additions and the implementation of a cost of living increase effective Q4 2013.

Share-based payments expense represents the value assigned to the granting of options and incentive-based units under the Company's Share Purchase Option Plan and Stock Based Compensation Plan respectively, using the Black-Scholes model.  For the year ended December 31, 2014 , $2,175 (2013: $2,392) was charged to expenses and included in contributed surplus in respect of these two plans.

EBITDA before share-based payments (See Non-GAAP Measures)

For the year ended December 31, 2014 , Canyon's increased activity resulted in EBITDA before share-based payments (see NON-GAAP MEASURES) for pressure pumping services of $118,989 , or 21% of revenues, compared to $38,409 , or 13% of revenues for the comparable 2013 year.

Fluid Management Services

000's except per share amounts
(Unaudited)

Year Ended
December 31

2014

2013

Revenues

$29,123

$-

Cost of services

(19,255)

66.1%

-

-%

Gross profit

9,868

33.9%

-

-%

Administrative expenses

(6,305)

21.7%

-

-%

Results from operating activities

3,563

12.2%

-

-%

Add non-cash item:

Depreciation and amortization

5,983

20.6%

-

-%

EBITDA before share-based payments (1)

$9,546

32.8%

$-

-%

Note (1):

See NON-GAAP Measures.

Revenues

The water management services business contributed $29,123 of revenues in 2014 over the period from acquisition of Fraction by Canyon on July 1, 2014 to December 31 , 2014.  As discussed above, water access restrictions in the northern regions of the WCSB were enacted late in the third quarter which impacted water transfer and fluid logistics revenues during in the current quarter. Storage tank rental revenues were also lower in the current quarter compared to the prior quarter due to lower activity by certain customers in response to the declining commodity prices as well as the deferral of a final investment decision by an LNG project sponsor.

Cost of services

Cost of services for the period ended December 31, 2014 totaled $19,255 and includes materials, products, transportation and repair costs of $9,941 , employee benefits expense of $6,335 , and depreciation of property and equipment of $2,979 .

Administrative expenses

Administrative expenses for the period ended December 31, 2014 totaled $6,305 and include employee benefits expense, depreciation of buildings and office equipment and amortization of intangibles and other administrative expenses.  Amortization of intangibles totals $2,884 and includes amortization of customer relationships and non-competition agreements pursuant to the acquisition of Fraction by Canyon effective July 1, 2014 .

EBITDA Before Share-Based Payments (See NON-GAAP MEASURES)

2014 EBITDA before share-based payments totaled $9,546 in the fluid management services division, or 33% of revenues.

Corporate

000's except per share amounts
(Unaudited)

Year Ended
December 31

2014

2013

Revenues

$-

$-

Administrative expenses

(8,866)

(7,711)

Results from operating activities

(8,866)

(7,711)

Add non-cash item:

Share-based payments expense

1,809

1,798

EBITDA before share-based payments (1)

$(7,057)

$(5,913)

Note (1):

See NON-GAAP Measures.

This segment consists of costs incurred to operate a public company, including corporate management, head office costs, corporate share-based payment expenses and professional fees.

Administrative expenses

Administrative expenses for the year ended December 31, 2014 totaled $8,866 (2013: $7,711 ) and include employee benefits expense, share-based payments, and other head office administrative expenses.

For the year ended December 31, 2014 , employee benefits expense increased due to the larger scale of Canyon's operations and due to transaction costs pertaining to the acquisition of Fraction.  Share-based payments expense represents the value assigned to the granting of options and incentive-based units under the Company's Share Purchase Option Plan and Stock Based Compensation Plan respectively, using the Black-Scholes model.  For the year ended December 31, 2014 $1,809 (2013 - $1,798 ) was charged to expenses and included in contributed surplus in respect of these two plans.

Other Items – Year Ended December 31, 2014 Statements of Operations

Finance costs

Finance costs include interest on bank indebtedness and finance lease obligations which total $1,512 for the year ended December 31, 2014 (2013: $658 ).  The increase in finance costs is due to the increase in loans and borrowings used to partially fund the Company's 2014 capital program.

Income tax expense

At the expected combined income tax rate of 25%, the income before income tax for the year ended December 31, 2014 of $66,230 would have resulted in an income tax expense of $16,558 , compared to the actual income tax expense of $17,136 .  The actual income tax expense was increased by non-deductible expenses.

EBITDA before share-based payments (See Non-GAAP Measures)

For the year ended December 31, 2014 , improved industry-wide conditions as previously discussed, resulted in an increase in consolidated EBITDA before share-based payments (see NON-GAAP MEASURES) to $121,478 from $32,496 recorded in the comparable 2013 year.

Income (loss) and comprehensive income (loss) and earnings (loss) per share

Income and comprehensive income totaled $49,094 for the year ended December 31, 2014 compared to loss and comprehensive loss of $4,375 in 2013.  The significant improvement in income and comprehensive income was due to the increase in activity as previously discussed.

Basic and diluted earnings per share were $0.75 and $0.74 respectively for the year ended December 31, 2014 compared to basic and diluted loss per share of $0.07 in 2013.

FORWARD-LOOKING STATEMENTS

This document contains certain forward-looking information and statements within the meaning of applicable securities laws.  The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "should", "believe", "plans" and similar expressions are intended to identify forward-looking information or statements.  In particular, but without limiting the foregoing, this document contains forward-looking information and statements pertaining to the following: future oil and natural gas prices; future results from operations; future liquidity and financial capacity and financial resources; future costs, expenses and royalty rates; future interest costs; future capital expenditures; future capital structure and expansion; the making and timing of future regulatory filings; and the Company's ongoing relationship with major customers.

The forward-looking information and statements contained in this document reflect several material factors and expectations and assumptions of the Company including, without limitation: that the Company will continue to conduct its operations in a manner consistent with past operations; the general continuance of current or, where applicable, assumed industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; certain commodity price and other cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to funds its capital and operating requirements as needed; and the extent of its liabilities.  The Company believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information and statements included in this document are not guarantees of future performance and should not be unduly relied upon.  Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of the Company's services; unanticipated operating results; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in the development plans of third parties; increased debt levels or debt service requirements; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; attracting and retaining skilled personnel and certain other risks detailed from time to time in the Company's public disclosure documents (including, without limitation, those risks identified in this document and the Company's Annual Information Form).

The forward-looking information and statements contained in this document speak only as of the date of the document, and none of the Company or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

SOURCE Canyon Services Group Inc.