CALGARY, ALBERTA--(Marketwire - May 4, 2012) - NuVista Energy Ltd. ("NuVista") (NVA.TO - News) is pleased to announce results for the three months ended March 31, 2012 and provide an update on its business plan. During the first quarter of 2012, we achieved significant success in our two key liquids-rich natural gas plays while adapting our business model for a period of lower natural gas prices. As the first stage of our Wapiti Montney play evaluation nears completion, we are very encouraged with the natural gas test rates, liquid yields, productivity and economics of this play. Results of our five well drilling program together with industry data supports our belief that the Wapiti Montney is a top-quartile North American natural gas play with the potential to create significant long term shareholder value.
Significant highlights for the first quarter of 2012 include:
-- Achieved funds from operations of $24.1 million for the three months
ended March 31, 2012 compared to $33.3 million for the same period in
2011 and $48.5 million for the three months ended December 31, 2011;
-- Achieved average production of 25,250 Boe/d compared to 26,078 Boe/d for
the same period in 2011 and 25,306 Boe/d for the three months ended
December 31, 2011;
-- Drilled 11 (9.0 net) wells during the first quarter resulting in 6 (5.0
net) heavy oil wells, 4 (3.0 net) liquids-rich natural gas wells and 1
(1.0 net) dry well testing a heavy oil prospect;
-- Completed a capital program of $52.9 million compared to $39.8 million
for the same period in 2011;
-- Completed and tested the fourth of our five well Wapiti Montney
delineation program with continued strong results. The fifth well was
rig released successfully ahead of schedule and under budget in late
April and is awaiting completion following spring break-up;
-- Expanded the geographic footprint of our W5 Spirit River/Notikewin play
by completing a high deliverability natural gas well in the Ferrier
area, which was drilled in the fourth quarter of 2011 and where we have
many follow-up locations; and
-- Completed the sale of a portion of our Pembina Cardium undeveloped land
and approximately 51 Boe/d of production for $9.2 million.
During the first quarter of 2012, we maintained production volumes similar to the fourth quarter of 2011 while lower commodity prices reduced cash flow. Realized prices for natural gas declined 34% to $2.39/Mcf while realized oil prices declined 13% to $70.73/Bbl compared to the fourth quarter of 2011. We are targeting 2012 year end debt of $307 million, equal to 2011 year end. At March 31, 2012, net long-term debt increased to $337 million as is normal for the busy winter drilling period. On April 30, 2012, our credit facility borrowing base was re-determined at $380 million. With debt levels expected to decline throughout the year, this borrowing base continues to be sufficient to advance our strategic goals.
For the remainder of 2012, a top priority will be to manage debt levels and maintain financial flexibility through this period of low natural gas prices. Our first quarter 2012 results have continued the strategic advancement of our three key plays and we are well prepared to accelerate development of our Wapiti Montney and other plays when natural gas prices increase from the current 10 year lows. We believe the low natural gas prices are already impacting industry supply and therefore recovery is expected to be near, but volatility and price risk are expected to remain high through the summer and fall so downside protection is warranted. We have continued with our price risk management program for crude oil and have entered into hedges for the remainder of 2012 to reduce the impact if gas prices deteriorate below current levels in the short term. For the second half of 2012 we have entered into natural gas price risk management contracts for 58 MMcf/d at an AECO costless collar price range of $1.70/GJ to $2.04/GJ or an equivalent corporate realized price of approximately $1.95/Mcf to $2.29/Mcf. This strategy protects 2012 downside while leaving 2013 price recovery upside fully intact. In addition to managing price volatility through incremental hedging, we are pursuing several other initiatives to ensure financial flexibility is improved, as outlined below.
2012 Divestiture Program
We are continuing our ongoing non-core divestiture program, with proceeds of over $50 million in the past year and $9 million year to date in 2012. Two non-core oil properties are currently being marketed with bid dates in the second quarter, and several more disposition packages are under evaluation. Proceeds will be used for the second half 2012 capital program while maintaining exit debt flat at approximately $307 million.
2012 Capital Program Flexibility
We have ensured that our drilling programs to date have placed us in a favorable position with respect to land expiries on most of our key plays leaving us with the ability to restrict or increase capital in response to the volatile commodity price environment. The twelve month, $70 million, Wapiti Montney five well capital program is largely behind us with minimal expenditures expected in the third quarter to complete the fifth well. We plan to restrict capital expenditures to minor non-discretionary expenditures until divestiture proceed targets are met, ensuring our debt targets are achieved. We will then begin modest spending after Spring break-up for oil wells and strategic liquids-rich natural gas wells, until gas prices recover. During the next few months, we will have the benefit of monitoring and learning from a significant amount of new production data from the wells in our key plays brought on production in the first quarter of 2012 and in the coming months. This information will provide clarity on our next strategic steps, scope of our key plays and spending plans as natural gas prices recover.
Wapiti Montney Ready to Proceed Into Early Development Stage
In March we tested the fourth of the five well delineation program on our north block of Montney land. Test rates after clean-up averaged 4.4 MMcf/d for the final 12 hours of a 70 hour test at 570 psig surface flowing pressure. These flow rates are very encouraging given the well was still flowing 1,700 Bbls/day of frac flowback water up the 2 3/8" production tubing at the time. The well will be tied-in for production in the third quarter following spring break-up, and is fully expected to meet our type curve expectations for this play. Further, the gas rate was increasing steadily from the beginning to the end of the entire 70 hour flow test as the well cleaned up. Free condensate production averaged 130 Bbls/d or 30 Bbls/MMcf while gas analysis indicates total natural gas liquids (NGL) production was 300 Bbls/d or 68 Bbls/MMcf if processed through a shallow cut plant, or over 125 Bbls/MMcf of NGL if processed through deep cut facilities.
During the first quarter, significant progress was made on the construction of the compressor/dehydration facility in our north block of landholdings and construction of pipelines for the tie-in of our second and third wells of the five well program completed earlier in 2012. We expect to have these wells on production in May at initial rates of approximately 6 MMcf/d to 10 MMcf/d per well with exact timing weather dependent. In April, we completed the drilling of our last well in the five well program, matching the record cost and speed of the fourth well, which was a pacesetter for the area. The completion, testing and tie-in of the fifth well is expected to occur in the third quarter following spring break-up.
For the remainder of 2012, we plan to complete the fifth well of the program, finish tie-ins, and complete the compressor/dehydration facility and related infrastructure. Further activity on our Montney lands in 2012 will be dependent on accessing additional capital as discussed earlier. We expect that the greater Wapiti resource will ultimately drive the construction of a large sour deep cut processing facility for all production in the area. Numerous medium and long term options for processing continue to evolve.
Based on the results that we have achieved to date from our five well delineation program and ongoing industry results, we believe this play is proving itself to be in the top quartile of North American gas plays. We have encouraging signs of an increasing production type curve and a reducing cost curve. With a high degree of repeatability and a significant degree of delineation achieved, we are poised to move into the development phase with momentum and very favorable economics. We have conducted a detailed petrophysical assessment of all our Montney land and have been integrating recently acquired test and production data from NuVista and industry wells. We have made significant upgrades to our internal resource assessment, and will be engaging a third-party engineering firm to prepare an independent evaluation. NuVista has identified the potential for over 500 wells and $3 billion to $4 billion of highly economic, repeatable capital investment in the Upper Montney portion of our land base alone. Assuming a WTI crude oil price of US$95.00/Bbl and historical condensate and NGL pricing relationships, breakeven natural gas price economics are as low as AECO $2.00/Mcf due to the significant condensate and liquids content. With the repeatable efficiencies of full development, we see the breakeven below $1.50/Mcf, underpinning this play's top quartile ranking. With the successful delineation program nearly complete, the time to seek funding alternatives to take this world class play to the next level is approaching. In this regard, several funding alternatives are currently being contemplated and will be communicated when a decision has been reached.
During the first quarter of 2012, we participated in 2 (1.0 net) Falher wells. We have now participated in 3 (1.5 net) Falher wells since late 2011. All these wells have high deliverability and high liquids yields, as disclosed in previous press releases for the first two wells. Test rates on the third well after clean-up averaged 10 MMcf/d for the final 12 hours of a 90 hour test at 3850 psig surface flowing pressure. Free condensate production over the test period averaged 210 Bbls/d or 21 Bbls/MMcf. At this rate, we estimate total C2+ production through the existing deep cut facility at 830 Bbls/d or 83 Bbls/MMcf. All three wells are now on production with rates expected to increase as we work through infrastructure commissioning and debottlenecking. These wells are economic even in the current natural gas price environment given their high production rates, low operating costs, and high liquids yields. We have identified approximately 24 gross (12 net) additional Falher locations with the timing of drilling additional wells based on available capital and strategic priorities.
W5 Spirit River/Notikewin
During the first quarter of 2012, we completed a high deliverability Notikewin natural gas well in the Ferrier area which was drilled in the fourth quarter of 2011. This well significantly expands the geographic footprint of our Spirit River/Notikewin opportunities from our success in the Alder Flats area. Test rates on this well after clean-up averaged 12 MMcf/d for the final 8 hours of a 70 hour test at 3400 psig surface flowing pressure. This well has been on production since February at a restricted rate of 6.5 MMcf/d and liquid yields of 110 Bbls/d or 17 Bbls/MMcf, with 55% of the liquids being free condensate. We have recently acquired 15 sections of offsetting Spirit River/Notikewin lands through private and Crown acquisitions and now have a total of 95 gross (64 net) sections in the Ferrier area and have identified 55 locations in Ferrier alone. This activity further increases our total W5 liquids-rich drilling inventory of 75 locations. With a constrained capital program in 2012 and low natural gas prices, we are deferring activity in our W5 Spirit River/Notikewin play until 2013, and are very well positioned to take it forward at that time.
W3/W4 Heavy Oil
We drilled 6 (5.0 net) wells targeting heavy oil during the first quarter of 2012 of which 4 wells (3.0 net) were at South Hallam. In total, 12 wells have now been placed on production in the Hallam South extension as we continue to drill and delineate the pool. All are economic oil producers however oilcuts continue to vary so we will monitor production results through spring break-up to refine our drilling program going forward. We drilled 1 (1.0 net) heavy oil well at Wildmere in eastern Alberta that is currently producing 150 Bbls/d as expected per type curve. This follows up on a successful and almost identical well drilled in December 2011 that has produced 40,700 Bbls to date and is currently producing at a rate of 70 Bbls/d. We currently anticipate 10 to 15 follow-up locations. For the remainder of the year, we will focus on monitoring production results and ongoing geological and reservoir analysis on several new oil plays across W3/W4 as well as our W5 core region to inform and expand our future drilling inventory.
Three months ended
($ thousands, except per share)
Oil and natural gas revenue 73,856 88,237
Funds from operations(1) 24,124 33,299
Per basic share 0.24 0.36
Per diluted share 0.24 0.36
Net earnings (loss) (3,147) 9,590
Per basic share (0.03) 0.10
Per diluted share (0.03) 0.10
Adjusted net earnings (loss)(1) (10,898) (7,092)
Per basic share (0.11) (0.08)
Per diluted share (0.11) (0.08)
Total assets 1,377,819 1,532,848
Long-term debt, net of adjusted working capital(1) 337,053 355,023
Capital expenditures 52,863 39,776
Property dispositions 9,163 -
Weighted average common shares outstanding
Basic 99,513 91,646
Diluted 99,513 91,646
Natural gas (MMcf/d) 105.5 107.4
Natural gas liquids (Bbls/d) 3,196 3,094
Oil (Bbls/d) 4,477 5,091
Total oil equivalent (Boe/d) 25,250 26,078
Average product prices(2)
Natural gas ($/Mcf) 2.39 4.02
Natural gas liquids ($/Bbl) 66.17 58.66
Oil ($/Bbl) 70.73 65.68
Natural gas and natural gas liquids ($/Mcfe) 1.73 1.76
Oil ($/Bbl) 16.75 15.46
Total oil equivalent ($/Boe) 11.50 11.50
Operating netback ($/Boe) 14.25 18.71
Funds from operations netback ($/Boe)(1) 10.50 14.19
1. Funds from operations, funds from operations per share, funds from
operations netback, operating netback, adjusted net earnings 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, refer to NuVista's "Management's Discussion and Analysis".
2. Product prices include realized gains/losses on commodity derivatives.
NuVista's production guidance for first the half of 2012 is unchanged at 24,500 Boe/d to 25,500 Boe/d despite minor divestitures and the shut-in of approximately 200 Boe/d of dry natural gas. Capital spending is forecast at the lower end of our previous guidance range of between $70 million and $80 million. Funds from operations for the first half of 2012 are forecast at approximately $40 million based on a forecast AECO natural gas price of $2.05/Mcf, WTI oil price of US$104.00/Bbl and incorporating our price risk management contracts. The first half capital budget is planned to modestly exceed funds from operations due to the busy winter drilling season however, as mentioned earlier, proceeds of asset dispositions are expected to make up any cash flow shortfall with $9 million already achieved year to date.
NuVista's disciplined deployment of capital on its material key plays, while maintaining a prudent focus on the balance sheet, has resulted in significant shareholder value creation over the past year and will lead to continued value creation over the long term. Over the next few months, additional production data from our Wapiti wells, the results from the various alternatives being pursued to access additional capital, and the outlook for natural gas prices is expected to provide clarity on our future growth plans. With a talented and motivated workforce and a business strategy focused on discipline, execution and profitability, we look forward to updating you on the progress in this value creation process as we move through 2012. Specific guidance for the second half of 2012 spending will be provided later in the second quarter when the items noted above have been brought to fruition.
CONSOLIDATED FINANCIAL STATEMENTS AND MD&A
First quarter 2012 interim consolidated financial statements and notes to the interim consolidated financial statements and Management's Discussion and Analysis for NuVista Energy Ltd. have been filed on SEDAR (www.sedar.com) under NuVista Energy Ltd. and can also be accessed on NuVista's website at www.nuvistaenergy.com.
ADVISORY REGARDING OIL AND GAS INFORMATION
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.
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; 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; expectations of future results, including future production levels, type curves and well economics, NuVista's planned capital budget; expectations with respect to NuVista's disposition program and its effect on debt levels; targeted debt level; the timing, allocation and efficiency of NuVista's capital program and the results therefrom; NuVista's plans and expectations with respect to operating during a period of low and volatile commodity prices; plans and expectations regarding facility construction and/or expansions, the timing thereof and the results therefrom; the anticipated potential of NuVista's asset base; forecast funds from operations; the source of funding of capital expenditures; the objectives and focus of NuVista's capital program and the allocation thereof and results therefrom; NuVista's risk management strategy; expectations regarding future commodity prices and netbacks; 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.
- natural gas
NuVista Energy Ltd.
President and CEO
Robert F. Froese
NuVista Energy Ltd.
VP, Finance and CFO