NuVista Energy Ltd. Announces Second Quarter 2013 Results

CALGARY, ALBERTA--(Marketwired - Aug. 12, 2013) - NuVista Energy Ltd. ("NuVista") (TSX:NVA) is pleased to announce results for the three and six months ended June 30, 2013 and provide an update on its business plan. During the second quarter of 2013, our operating and financial results began to reflect the tremendous growth potential and strong economics of our condensate-rich Wapiti Montney play. Included in this press release are the initial 30 day production rates from two new wells brought on production in June which continue to highlight the strong condensate yields and prolific nature of this significant resource. The results of our drilling program together with industry data continue to support our belief that the condensate-rich Wapiti Montney is a top-decile North American natural gas play. The current phase of production growth is well underway through existing connected facilities, and progress continues to be made towards the next phase of growth in mid 2014 with the construction of a 65 MMcf/d compressor station in our South Wapiti Block of land to connect with the egress arrangements secured and previously announced with Keyera Corp. through the Simonette gas plant.

Highlights for, and subsequent to, the second quarter of 2013 are as follows:

  • Achieved an average production rate for the second quarter of 2013 of 17,799 Boe/d, 19% higher than the 14,903 Boe/d recorded in the first quarter of 2013 and well above second quarter guidance. First half 2013 production of 16,359 Boe/d is slightly above the high end of our guidance range of 15,250 Boe/d to 16,250 Boe/d provided in March 2013.
  • Achieved funds from operations of $19.0 million compared to $11.6 million in the first quarter of 2013 resulting in a quarter over quarter increase of 64%. Higher value condensate production doubled from 990 Bbls/d in the first quarter to 1,980 Bbls/d in the second quarter. This increase corresponded to a marked shift in the distribution in NuVista's revenue stream quarter over quarter. Condensate volumes generated 31% of total revenue up from 22% in the first quarter. Total oil and liquids volumes accounted for 58% of NVA's second quarter revenue.
  • Wapiti Montney production grew to 4,730 Boe/d in the second quarter from 1,830 Boe/d in the first quarter of 2013 reflecting the strong results of the 2013 drilling program to date. Wapiti Montney production has grown to 27% of total production volumes with Montney field netbacks reaching $28.90/Boe. When combined with our up-hole sweet production, the Wapiti core operating area accounted for 57% of total company production volumes in the second quarter.
  • Increased the number of Wapiti Montney wells on production to 11 with another strong well tracking the typecurve in our North Block and another exceptional well in our South Block. IP 30 condensate production from these wells based on field estimates are 254 Bbls/d (51 Bbls/MMcf) and 535 Bbls/d (103 Bbls/MMcf), respectively. Total IP30 production for these wells was 1,067 Boe/d and 1,383 Boe/d respectively. Please refer to the table below for details.
  • Completed a third Montney delineation well in the second quarter that is currently in the process of being tied-in.
  • Subsequent to the end of the second quarter we have begun drilling three additional wells spanning our North and South Blocks in pursuit of development step-out drilling near existing strong wells, delineation, and continued land expiry management.
  • Achieved a new company record this month by reaching total depth (TD) on one of the above wells in 26 days spud-to-TD for $4.2 million drilling cost, four days and $0.4 million (9%) less than our prior record well. Drill times and costs continue to trend downwards in general.
  • Continued strong results from our South Block well (#9 in the table below) originally disclosed in May 2013, with cumulative condensate production now up to 60,000 Bbls in just 84 days. Based on the current trend this well will reach payout in nine months.

Strong Wapiti Montney Progress Continues

We continue to be very pleased with the progress made in advancing our Wapiti Montney play and the results from our and industry's wells in the greater Wapiti area. With every well drilled we increase our understanding and believe that we are still at the early stages of fully maximizing the economic value from this play. We are currently in the process of developing options for 2014 capital spending and growth based on the evaluation of recent well results, commodity prices and balance sheet flexibility. We continue to be encouraged by our emerging well results defining the potential for proven development pods, particularly in our highly condensate-rich South Block. Please see below a table of well results including updated cumulative production for wells drilled to date, and results from the two new wells (#10 and #11). Due to continued positive results we have determined it prudent to change our typecurve projections for all future South Block wells from an average condensate recovery of 45 Bbls/MMcf raw to 75 Bbls/MMcf of condensate, with the raw gas typecurve remaining as before at 4.4 Bcf raw. North Block well forward projections will remain for now at the same as previous, 4.4 Bcf raw gas and 45 Bbls/MMcf condensate.

Table of Well Results

IP30 Production(1)


Raw Gas


Total Sales
(MMcf/d) (Bbls/d) (Boe/d) (C5+/raw)
Original Typecurve
4.4 Bcf Raw Gas
5.8 203 1,139 35
Average of 1st 6 wells 5.4 305 1,146 59
Well 7 (North)(3) 6.7 346 1,479 57
Well 8 (South)(3) 3.4 390 918 116
Well 9 (South)(3) 7.2 935 2,003 129
Average of next 3 wells 5.8 557 1,467 101
New Well 10 (North) 5.0 254 1,067 51
New Well 11 (South) 5.2 535 1,383 103
Cumulative Production to July 24, 2013

Days on


Sales Gas

(C5+/raw) (Bbls) (MMcf) (MBoe)
Original Typecurve
4.4 Bcf Raw Gas





Well 1 (North) 812 34 39,000 1,000 221
Well 2 (South) 339 41 34,000 774 170
Well 3 (North) 334 40 46,000 948 223
Well 4 (North) 287 79 43,000 441 127
Well 5 (North) 241 54 47,000 762 193
Well 6 (South) 151 65 19,000 266 65
Well 7 (North) 97 52 25,000 428 108
Well 8 (South) 96 104 27,000 216 69
Well 9 (South) 84 113 60,000 422 141
Well 10 (North) 46 51 11,000 179 46
Well 11 (South) 26 105 14,000 111 36
(1) Excludes non-producing days and wells 10 and 11 are based on field estimates
(2) Condensate gas ratio
(3) Previously disclosed field estimates have been updated for actual results

After substantial cash flow and production growth from the first to the second quarter, production for the third quarter of 2013 is expected to be relatively flat to the second quarter. Production growth is expected to resume again in the fourth quarter as a result of an active third quarter drilling program. Faster cycle times for wells drilled in the second quarter ahead of spring break-up and the delay in the start-up of the third quarter drilling program due to the extended Alberta spring rains effectively swapped some of our third quarter production growth into the second quarter. The net effect of this is that we expect to be right on track with the higher end of original production guidance for 2013, but with phasing changes quarter to quarter. We continue to focus on reducing drilling times and costs in addition to optimizing completions and have continued to meet or exceed cost reduction targets as outlined in the highlights above and in our public Corporate Presentation. Our average proved plus probable play recycle ratios are already well over 2x and are expected to continue as previously forecast towards 3x as our optimizations continue.

The significance of the Montney economics is beginning to flow through to our quarterly results. Montney field netbacks have reached $28.90/Boe in the second quarter despite being in the early stages of development and the temporarily increased operating costs we have incurred for additional condensate trucking and ramp-up transition costs due to recent above-typecurve wells. These temporary issues will be remedied in stages with resolution expected through 2014 when the previously announced processing and transportation infrastructure is in place. Corporate netbacks are expected to continue to grow significantly as Wapiti Montney volumes increasingly take their place as a dominant percentage of the company output and the benefits of longer term transportation and processing arrangements are realized. Overall, these short term issues and a one time annual Gas Cost Allowance adjustment reduced quarterly cash flows by approximately $2 million in the quarter.

We remain excited about the progress on our South Block compressor station towards mid 2014 startup to feed the new Keyera pipeline and Simonette plant firm processing contract. Major long lead equipment has been ordered for the NuVista compressor station for early 2014 installation, and Keyera project plans also remain on schedule. Production will begin mid 2014 with capacity of 35 MMcf/d raw, ramping up to 65 MMcf/d by late 2014. As previously disclosed, this project brings NuVista significant room for growth, reduced Montney operating costs in the range of 25-33%, and firm access for all Montney C3+ volumes for fractionation and market access at Keyera Fort Saskatchewan.

Access to markets and fractionation for natural gas liquids products continues to be a challenge for our industry. It is critical that volumes can move smoothly and efficiently to market to facilitate play growth. In this regard, NuVista is very well positioned to meet the industry challenges for the transportation, processing, and marketing of Wapiti Montney products through a variety of firm contracts which have been set in place including:

  • All foreseeable raw gas in 2013 will access processing at SemCAMS K3 and CNRL Gold Creek plants;
  • Significant growth volumes for 2014 and 2015 will access processing by adding the Keyera Simonette pipeline and gas plant processing, with facilities already under construction;
  • All condensate volumes will be transported by pipeline and truck to the local Alberta market for 2013, with virtually all volumes expected to be pipeline delivered by late 2014;
  • All 2013 and beyond propane and butane volumes are being transported on the Pembina Peace Pipeline with primarily firm commitments to Fort Saskatchewan, where they will be fractionated and delivered to market under firm service contracts with Keyera in Fort Saskatchewan.

Commodity hedging is a key component of NuVista's financial risk management initiatives. There has been much attention recently directed to the TransCanada Eastern Mainline toll changes, and much concern about the corresponding impact on AECO natural gas prices. In anticipation of this change to tolls, NuVista stepped up its hedging program several months ago. NuVista's Board of Directors has increased the authorized hedging period from two years to three years under specific circumstances and has formalized the inclusion in our internal policy the hedging of natural gas basis risk. For the third quarter of 2013, NuVista has fixed an AECO floor price on its natural gas production of $3.19/Mcf on approximately 60% of forecast production, net of royalties. For the fourth quarter of 2013, NuVista has fixed a floor AECO price of $3.36/Mcf on approximately 40% of its net forecast production, and has changed the floating price exposure through AECO/NYMEX basis hedges on a further 30% of net production volumes from an AECO price to a NYMEX price less US$0.56/MMbtu. This strong AECO fixed and AECO/NYMEX basis protection continues through 2014. For the remainder of 2013, NuVista has also fixed a WTI crude oil floor price of $93.38/Bbl on approximately 55% of its net forecast oil and liquids production.

A disciplined approach to financial risk management continues to be one of our core principles and is key to our successful advancement of the Wapiti Montney play and the creation of shareholder value. During this period of significant opportunity, production growth, and uncertain commodity prices, NuVista remains committed to maintaining financial flexibility by keeping net debt at or below approximately 1.5x the most recent quarter's annualized cash flow.

2013 Production Guidance Unchanged

We are pleased to reiterate our full year 2013 guidance. Our capital spending for the year is anticipated to be between $210 million and $220 million. Average production forecast for the year is expected to be 16,250 Boe/d to 17,000 Boe/d, trending towards the top half of the guidance range. Production for the third quarter of 2013 is forecast to be relatively flat with the second quarter with a range of 17,000 Boe/d to 17,750 Boe/d. Fourth quarter production is expected to increase to between 17,500 Boe/d and 18,500 Boe/d as previously disclosed. Funds from operations for the year are forecast to be between $70 million and $75 million based on forecast second half of 2013 AECO and NYMEX natural gas prices of $3.15/Mcf and US$3.70/MMbtu respectively, and a WTI crude oil price of US$103/Bbl.

We continue to evaluate various scenarios pertaining to pace of growth for our 2014 business plan, and we look forward to announcing additional details in the fall. With every well drilled, we are learning more about our Wapiti Montney play and growing increasingly confident and excited about the impressive condensate-rich potential of this play, the growth potential, and the exceptional value that is and will be created from this play as we increase scale and benefit from the efficiencies that come with it. We have the people, the assets, and the processing capacity to continue to deliver strong results for our shareholders. We look forward to providing an update and 2014 spending details in early November with the release of our third quarter results.

Corporate Highlights
Three months ended
June 30,
Six months ended
June 30,
($ thousands, except per share) 2013 2012 2013 2012
Oil and natural gas revenue 54,158 58,201 95,906 132,057
Funds from operations(1) 18,983 18,083 30,612 42,207
Per basic share 0.16 0.18 0.26 0.42
Per diluted share 0.16 0.18 0.26 0.42
Net earnings (loss) (7,383 ) (85,411 ) (11,444 ) (88,558 )
Per basic share (0.06 ) (0.86 ) (0.10 ) (0.89 )
Per diluted share (0.06 ) (0.86 ) (0.10 ) (0.89 )
Adjusted net earnings (loss)(1) (4,850 ) (14,668 ) (13,471 ) (25,566 )
Per basic share (0.04 ) (0.15 ) (0.11 ) (0.26 )
Per diluted share (0.04 ) (0.15 ) (0.11 ) (0.26 )
Total assets 934,089 1,254,462
Long-term debt, net of adjusted working capital(1) 94,786 339,111
Capital expenditures 30,963 18,805 99,752 70,652
Dispositions (204 ) - 12,392 9,163
Weighted average common shares outstanding (thousands):
Basic 118,665 99,513 118,643 99,513
Diluted 118,665 99,513 118,643 99,513
Natural gas (MMcf/d) 73.5 98.1 68.2 101.8
Condensate (Bbls/d) 1,980 1,246 1,485 1,221
Butane (Bbls/d) 502 529 437 539
Propane (Bbls/d) 737 709 662 722
Ethane (Bbls/d) 985 641 874 679
Oil (Bbls/d) 1,354 3,994 1,542 4,236
Total oil equivalent 17,799 23,467 16,359 24,359
Average product prices (2)
Natural gas ($/Mcf) 3.43 2.00 3.34 2.25
Condensate ($/Bbl) 92.90 95.05 96.32 102.42
Butane ($/Bbl) 50.57 60.75 56.10 69.02
Propane ($/Bbl) 19.22 20.02 21.89 28.24
Ethane ($/Bbl) 9.62 2.25 7.90 9.18
Oil ($/Bbl) 81.67 69.35 73.28 72.73
Operating expenses
Natural gas and natural gas liquids ($/Mcfe) 1.86 1.66 1.86 1.69
Oil ($/Bbl) 24.71 15.55 22.13 16.18
Total oil equivalent ($/Boe) 12.19 10.91 12.20 11.21
Operating netback ($/Boe) 16.34 12.72 15.29 13.52
Funds from operations netback ($/Boe)(1) 11.72 8.47 10.35 9.53
(1) Funds from operations, 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 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 excludes the current portions of the commodity derivative asset or liability. 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.


NuVista's second quarter 2013 interim consolidated financial statements and the accompanying Management's Discussion and Analysis will be filed on SEDAR ( under NuVista Energy Ltd. and can also be accessed on NuVista's website at


This news release contains the terms barrels of oil equivalent ("Boe") and thousand cubic feet equivalent ("Mcfe"). Natural gas is converted to a Boe using six thousand cubic feet of gas to one barrel of oil. In certain circumstances natural gas liquid volumes have been converted to a Mcfe on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are 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 than 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 or test 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. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.


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; the expectations of creating significant shareholder value from NuVista's properties and opportunities; forecast production; production mix; drilling, development, completion and tie-in plans and results; plans to reduce drilling times and costs and to optimize completions; plans relating to future access to processing facilities and markets; expectations of future results, including future production levels, typecurves, well economics, and operating costs, targeted debt level; the timing, allocation and efficiency of NuVista's capital program and the results therefrom; plans and expectations regarding facility construction and/or expansions, the timing thereof and the benefits to be obtained therefrom; the anticipated potential of NuVista's asset base; forecast funds from operations; the source of funding of capital expenditures; NuVista's risk management strategy; expectations regarding future commodity prices and netbacks; industry conditions and the timing of release of future results.

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, access to infrastructure and markets, 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 has included the forward-looking statements in this press release in order to provide readers with a more complete perspective on NuVista's future operations and such information may not be appropriate for other purposes. 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.

Contact Information:

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

Robert F. Froese
VP, Finance and CFO
(403) 538-8530