NuVista Energy Ltd. ("NuVista") (TSX:NVA) 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.
Wapiti Falher
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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate Highlights
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31,
2012 2011
----------------------------------------------------------------------------
Financial
($ 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
(thousands):
Basic 99,513 91,646
Diluted 99,513 91,646
----------------------------------------------------------------------------
Operating
Production
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 ($/Bbl) 70.73 65.68
Operating expenses
Natural gas and natural gas liquids ($/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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NOTES:
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.
2012 GUIDANCE
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.
|
