CALGARY, ALBERTA -- (Marketwired) -- 07/31/14 -- Baytex Energy Corp. ("Baytex") (TSX: BTE) (NYSE: BTE) reports its operating and financial results for the three and six months ended June 30, 2014 (all amounts are in Canadian dollars unless otherwise noted).
Commenting on the results, James Bowzer, President and Chief Executive Officer, said: "We are pleased to report our second quarter results which include twenty days of operations for our recently acquired Eagle Ford assets. The Eagle Ford is one of the premier oil resource plays in North America and will be an important growth engine for Baytex going forward. Our results reflect strong production volumes, increased funds from operations, and improved netbacks. For the second half of this year, we will continue to implement our capital program with over 90% of our spending directed to our three key oil resource plays which provide some of the highest rate of return projects in North America. We are pleased with our direction and well positioned to deliver future growth and income."
Highlights
-- Closed the $2.8 billion acquisition of Aurora Oil & Gas Limited
("Aurora") adding 22,350 net contiguous acres in the Sugarkane Field
located in South Texas in the core of the liquids-rich Eagle Ford shale;
-- Generated production of 66,934 boe/d (87% oil and NGL) in Q2/2014, an
increase of 12% over Q1/2014 and 15% over Q2/2013;
-- Delivered funds from operations ("FFO") of $202.5 million ($1.49 per
basic share) during Q2/2014 (excluding acquisition-related costs of $37
million), an increase of 19% over Q1/2014 and 30% over Q2/2013;
-- Realized an operating netback (sales price less royalties, production
and operating expenses, and transportation expenses) in Q2/2014 of
$40.74/boe, an increase of 11% over Q1/2014 and 28% over Q2/2013;
-- Maintained a conservative payout ratio, net of Dividend Reinvestment
Plan ("DRIP") participation, of 37% (47% before DRIP) in Q2/2014;
-- Issued US$800 million of senior unsecured notes in two equal tranches of
US$400 million with maturities of seven and ten years bearing interest
at 5.125% and 5.625%, respectively;
-- Increased the monthly dividend on our common shares by 9% to $0.24 from
$0.22 per share; and
-- Subsequent to the quarter, announced the divestiture of our North Dakota
assets for gross proceeds of approximately $357 million (US$330.5
million).
Three Months Ended Six Months Ended
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June 30, March 31, June 30, June 30, June 30,
2014 2014 2013 2014 2013
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FINANCIAL
(thousands of Canadian
dollars, except per
common share amounts)
Petroleum and natural
gas sales $ 476,404 $ 385,809 $ 341,011 $ 862,213 $ 613,956
Funds from operations
(1) 165,503 170,810 155,804 336,312 257,576
Per share - basic 1.22 1.36 1.26 2.57 2.09
Per share - diluted 1.21 1.34 1.25 2.54 2.07
Cash dividends
declared (2) 75,397 63,441 60,326 138,838 116,775
Dividends declared per
share 0.68 0.66 0.66 1.34 1.32
Net income 36,799 47,841 36,192 84,640 46,341
Per share - basic 0.27 0.38 0.29 0.65 0.37
Per share - diluted 0.27 0.38 0.29 0.64 0.37
Exploration and
development 148,916 172,425 177,834 321,341 344,356
Acquisitions, net of
divestitures 2,920,845 673 (1,796) 2,921,518 (23,227)
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Total oil and natural
gas capital
expenditures $3,069,761 $ 173,098 $ 176,038 $3,242,859 $ 321,129
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Bank loan $ 952,402 $ 300,564 $ 225,434 $ 952,402 $ 225,434
Long-term debt 1,329,487 465,795 457,680 1,329,487 457,680
Working capital
deficiency 178,517 65,909 87,418 178,517 87,418
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Total monetary debt
(3) $2,460,406 $ 832,268 $ 770,532 $2,460,406 $ 770,532
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Three Months Ended Six Months Ended
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June 30, March 31, June 30, June 30, June 30,
2014 2014 2013 2014 2013
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OPERATING
Daily production
Light oil and NGL
(bbl/d) 12,340 7,457 8,202 9,912 8,062
Heavy oil (bbl/d) 45,986 45,232 42,510 45,611 40,012
Total oil and NGL
(bbl/d) 58,326 52,689 50,712 55,523 48,074
Natural gas (mcf/d) 51,645 40,886 45,148 46,295 42,243
Oil equivalent (boe/d @
6:1) (4) 66,934 59,502 58,236 63,239 55,115
Average prices (before
hedging)
WTI oil (US$/bbl) 102.99 98.68 94.22 100.84 94.30
WCS heavy oil (US$/bbl) 82.95 75.55 75.07 79.25 68.75
Edmonton par oil ($/bbl) 106.68 100.18 92.94 103.43 90.77
LLS oil (US$/bbl) 105.55 104.38 104.81 104.96 109.37
Baytex heavy oil ($/bbl)
(5) 79.26 71.13 63.92 75.26 59.07
Baytex light oil and NGL
($/bbl) 91.03 85.18 77.85 88.84 77.30
Baytex total oil and NGL
($/bbl) 81.74 73.12 66.17 77.68 62.12
Baytex natural gas
($/mcf) 4.84 5.22 3.59 5.01 3.53
Baytex oil equivalent
($/boe) 75.06 68.33 60.42 71.92 56.90
CAD/USD noon rate at
period end 1.0676 1.1053 1.0512 1.0676 1.0512
CAD/USD average rate for
period 1.0894 1.1035 1.0231 1.0964 1.0159
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TSX
Share price (Cdn$)
High 49.88 45.65 43.05 49.88 47.60
Low 44.30 38.90 36.37 38.90 36.37
Close 45.89 45.52 37.90 45.89 37.90
Volume traded (thousands) 45,952 53,781 30,085 99,733 57,853
NYSE
Share price (US$)
High 46.30 41.28 42.50 46.30 47.47
Low 40.70 35.34 34.71 35.34 34.71
Close 42.16 41.13 36.04 42.16 36.04
Volume traded (thousands) 3,552 4,150 4,763 7,702 8,132
Common shares outstanding
(thousands) 165,421 126,442 123,593 165,421 123,593
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Notes:
(1) Funds from operations is not a measurement based on generally accepted
accounting principles ("GAAP") in Canada, but is a financial term
commonly used in the oil and gas industry. We define funds from
operations as cash flow from operating activities adjusted for finance
costs, changes in non-cash operating working capital and other operating
items. Baytex's funds from operations may not be comparable to other
issuers. Baytex considers funds from operations a key measure of
performance as it demonstrates its ability to generate the cash flow
necessary to fund future dividends and capital investments. For a
reconciliation of funds from operations to cash flow from operating
activities, see Management's Discussion and Analysis of the operating
and financial results for the three and six months ended June 30, 2014.
(2) Cash dividends declared are net of DRIP participation.
(3) Total monetary debt is a non-GAAP measure which we define to be the sum
of monetary working capital (which is current assets less current
liabilities (excluding non-cash items such as unrealized gains or losses
on financial derivatives, assets held for sale and liabilities related
to assets held for sale)), the principal amount of long-term debt and
long-term bank loan.
(4) Barrel of oil equivalent ("boe") amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel
of oil. The use of boe amounts may be misleading, particularly if used
in isolation. A boe conversion ratio of six thousand cubic feet of
natural gas to one barrel of oil is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(5) Heavy oil prices exclude condensate blending.
Acquisition of Aurora
On June 11, 2014, we completed the acquisition of Aurora for total consideration of approximately $2.8 billion. Aurora's primary asset consists of 22,350 net contiguous acres in the Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford shale. The Sugarkane Field has been largely delineated with infrastructure in place which is expected to facilitate future annual production growth. In addition, these assets have future reserves upside potential from well downspacing, improving completion techniques and new development targets in additional zones. Our second quarter results include twenty days of operations from the Eagle Ford assets representing the period from June 11 to June 30.
To finance the acquisition of Aurora, we completed the issuance of 38,433,000 subscription receipts at $38.90 each on February 24, 2014, raising gross proceeds of approximately $1.5 billion. These subscription receipts were subsequently exchanged for common shares upon closing of the acquisition. We also issued US$800 million of senior unsecured notes in two equal tranches of US$400 million with maturities of seven and ten years bearing interest at 5.125% and 5.625%, respectively. The proceeds from the issuance of the senior unsecured notes were used to retire existing debt of Aurora.
Update on Portfolio Review
In anticipation of the Eagle Ford transaction, we initiated a portfolio review of our assets late in the second quarter. During this review we identified assets representing 5% to 10% of our production that are not likely to command capital going forward given our plans to direct capital to the highest rate of return projects in our portfolio. Subsequent to the quarter, we have entered into an agreement to sell our North Dakota assets, effective July 1, 2014, for gross proceeds of approximately $357 million (US$330.5 million). The transaction is expected to close toward the end of the third quarter with after tax net proceeds from this sale, estimated at $275 million, to be applied against outstanding bank indebtedness. Production from our North Dakota assets averaged 3,200 boe/d in Q2/2014. We will continue to assess the market for any future divestitures.
Operations Review
Our operational execution remains on track with second quarter production volumes and capital spending consistent with our full-year plans. Production averaged 66,934 boe/d (87% oil and NGL) during Q2/2014, an increase of 12% from Q1/2014 and 15% from Q2/2013.
Our base business (excluding the Eagle Ford) contributed production of 60,828 boe/d (88% oil and NGL) during Q2/2014, an increase of 2% from Q1/2014 and 4% from Q2/2013. Production from the Eagle Ford averaged 27,783 boe/d (83% oil and NGL) for the 20-day period resulting in a contribution of 6,106 boe/d to our production volumes for Q2/2014.
Capital expenditures for exploration and development activities totaled $148.9 million in Q2/2014 and included the drilling of 51 (28.3 net) wells with a 100% success rate. Capital expenditures (excluding the Eagle Ford) for exploration and development activities totaled $122.9 million in Q2/2014 and included the drilling of 40 (25.4 net) wells. Capital expenditures for the Eagle Ford assets totaled $26.0 million and included the drilling of 11 (2.9 net) wells.
We are updating our 2014 guidance to reflect the expected closing date of the North Dakota asset sale. Our capital spending plans are unchanged as we had previously incorporated a reduction in spending in North Dakota in the second half of this year. For the second half of 2014, capital expenditures for exploration and development activities are forecast to be $440 to $465 million and we expect to generate an average production rate of 86,000 to 88,000 boe/d (previously 88,000 to 90,000 boe/d). Our full-year 2014 production guidance is 74,000 to 76,000 boe/d (previously 75,000 to 77,000 boe/d) with budgeted exploration and development expenditures of $765 to $790 million.
Wells Drilled - Three Months Ended June 30, 2014
Crude Oil
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Primary Thermal Natural Gas
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Gross Net Gross Net Gross Net
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Heavy oil
Lloydminster 21 9.2 2 2.0 - -
Peace River 12 12.0 - - - -
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33 21.2 2 2.0 - -
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Light oil, NGL and natural gas
Eagle Ford 11 2.9 - - - -
Western Canada - - - - - -
North Dakota 5 2.2 - - - -
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16 5.1 - - - -
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Total 49 26.3 2 2.0 - -
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Stratigraphic Dry and
and Service Abandoned Total
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Gross Net Gross Net Gross Net
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Heavy oil
Lloydminster - - - - 23 11.2
Peace River - - - - 12 12.0
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- - - - 35 23.2
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Light oil, NGL and natural gas
Eagle Ford - - - - 11 2.9
Western Canada - - - - - -
North Dakota - - - - 5 2.2
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- - - - 16 5.1
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Total - - - - 51 28.3
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Wells Drilled - Six Months Ended June 30, 2014
Crude Oil
----------------------------
Primary Thermal Natural Gas
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Gross Net Gross Net Gross Net
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Heavy oil
Lloydminster 113 71.1 2 2.0 - -
Peace River 20 20.0 - - - -
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133 91.1 2 2.0 - -
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Light oil, NGL and natural gas
Eagle Ford 11 2.9 - - - -
Western Canada 6 5.7 - - 2 2.0
North Dakota 11 4.7 - - - -
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28 13.3 - - 2 2.0
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Total 161 104.4 2 2.0 2 2.0
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Stratigraphic Dry and
and Service Abandoned Total
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Gross Net Gross Net Gross Net
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Heavy oil
Lloydminster 13 13.0 2 2.0 130 88.1
Peace River 24 24.0 - - 44 44.0
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37 37.0 2 2.0 174 132.1
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Light oil, NGL and natural gas
Eagle Ford - - - - 11 2.9
Western Canada - - - - 8 7.7
North Dakota - - - - 11 4.7
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- - - - 30 15.3
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Total 37 37.0 2 2.0 204 147.4
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In Q2/2014, heavy oil production averaged 45,986 bbl/d, an increase of 2% from Q1/2014 and 8% from Q2/2013. During Q2/2014, we drilled 35 (23.2 net) oil wells on our heavy oil properties.
Production from our Peace River area properties averaged approximately 26,100 bbl/d in Q2/2014, an increase of 1% from Q1/2014 and 15% from Q2/2013. We drilled 12 (12.0 net) cold horizontal producers encompassing a total of 148 laterals in the Peace River area.
In our Lloydminster heavy oil area, Q2/2014 drilling included 19 (8.8 net) horizontal oil wells and two (0.4 net) vertical oil wells with a 100% success rate. We continue to expand the use of multi-lateral horizontal drilling techniques, drilling two horizontal wells at Lloydminster with two and four laterals, respectively.
In the Cliffdale area of Peace River, thermal operations continued as planned with steam injection at Pad 2 commencing on schedule in early June. A modified injection and completion strategy to improve uniform horizontal well heat distribution is showing early positive results.
At the Gemini steam-assisted gravity drainage pilot project, oil production commenced in early April, 2014. The 600m horizontal well pair is currently producing approximately 1,000 bbl/d, which is in line with our expectations. We continue to analyze reservoir performance to confirm viability of a commercial development plan.
In the Eagle Ford, we participated in the drilling of 11 (2.9 net) wells. As at June 30, drilling operations were underway on 10 gross wells, 40 gross wells were awaiting fracture stimulation and 12 gross wells were being stimulated or prepared for production. Our average working interest for these wells is approximately 27%.
Financial Review
We generated FFO (excluding $37.0 million of acquisition-related costs) of $202.5 million ($1.49 per basic share) during Q2/2014, representing an increase of 19% from Q1/2014 and 30% from Q2/2013. The higher FFO is attributable to increased production (mainly due to the Aurora acquisition) and higher commodity prices. Inclusive of the acquisition-related costs, FFO totaled $165.5 million ($1.22 per basic share) during Q2/2014.
The average WTI price for Q2/2014 was US$102.99/bbl, representing an increase of 4% from Q1/2014 and 9% from Q2/2013. The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 19.0% in Q2/2014, as compared to 23.4% in Q1/2014 and 20.0% in Q2/2013. The strong market conditions for WCS reflect increased refinery demand in the U.S. Midwest, a continued increase in crude by rail volumes and normal seasonality.
Our realized total oil and NGL price of $81.74/bbl in Q2/2014 increased by 12% from $73.12/bbl in Q1/2014 and 24% from $66.17/bbl in Q2/2013. We continue to see strong price realizations for our heavy oil. Our realized heavy oil price of $79.26/bbl (88% of WCS) in Q2/2014 increased by 11% from $71.13/bbl (85% of WCS) in Q1/2014 and 24% from $63.92/bbl (83% of WCS) in Q2/2013. These improved price realizations reflect both strong benchmark prices and contributions from rail as we continue to increase our utilization of rail. In Q2/2014, approximately 55% of our heavy oil volumes were delivered to market by rail, as compared to 42% for full-year 2013. For Q3/2014, we expect to deliver approximately 60% of our total heavy oil volumes to market by rail.
We generated an operating netback (excluding financial derivatives) of $40.74/boe in Q2/2014, up 11% from $36.85/boe in Q1/2014 and up 28% from $31.71/boe in Q2/2013. Our Canadian operations generated an operating netback of $38.78/boe while the Eagle Ford generated an operating netback for the twenty-day period ending June 30 of $53.97/boe. The table below provides a summary of our Q2/2014 netback.
Three
Months
Ended
Three Months Ended June 30,
June 30, 2014 2013
---------------------------------
Eagle
($ per boe) Canada Ford(1) Total Change
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Sales Price $ 72.85 $ 85.47 $ 75.06 $ 60.42 24%
Less:
Royalties 16.98 24.78 18.36 11.66 57%
Production and
operating expenses 13.07 4.65 12.32 12.97 (5)%
Transportation
expenses 4.02 2.07 3.64 4.08 (11)%
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Operating netback $ 38.78 $ 53.97 $ 40.74 $ 31.71 28%
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(1) Eagle Ford netback reflects the 20-day period from June 11 to June 30,
2014.
As part of our hedging program, we are focusing on opportunities to further mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail. During the second quarter, we entered into our first Brent-based fixed differential physical heavy oil sale. This six-month term rail contract runs from October 1, 2014 to March 31, 2015 and is expected to represent approximately 25% of our crude by rail volumes.
For Q3/2014, we have entered into hedges on approximately 51% of our WTI exposure at a weighted average price of US$96.45/bbl. We have also reduced our exposure to WCS price differentials through a combination of long term physical supply contracts and rail delivery on approximately 45% of our heavy oil production. In addition, we have hedged approximately 54% of our natural gas price exposure and 29% of our exposure to currency movements between the U.S. and Canadian dollars.
Total monetary debt at the end of Q2/2014 is $2.46 billion. With $461 million in undrawn capacity on existing credit facilities, we have ample liquidity to allow us to execute our growth and income model. We continue to target a total monetary debt to FFO ratio under 2.0 times.
Additional Information
Our unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2014 and related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
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Conference Call Today
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call today, July 31, 2014, starting at 9:00am
MDT (11:00am EDT). To participate, please dial 416-340-9531 or toll free in
North America 1-866-902-2211 and toll free international 1-800-2787-2090.
Alternatively, to listen to the conference call online, please enter
http://www.gowebcasting.com/5668 in your web browser.
An archived recording of the conference call will be available until August
7, 2014 by dialing toll free 1-800-408-3053 within North America (Toronto
local dial 905-694-9451, International toll free 1-800-3366-3052) and
entering reservation code 5817148. The conference call will also be archived
on the Baytex website at http://www.baytexenergy.com/.
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Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this press release contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; the anticipated benefits from the acquisition of Aurora, including our beliefs that the acquisition will be an excellent fit with our business model and will provide shareholders with exposure to projects with attractive capital efficiencies; our expectations that the Aurora assets have infrastructure in place that support future annual production growth and that such assets will provide material production, long-term growth and high quality reserves with upside potential; our expectations regarding the effect of well downspacing, improving completion techniques and new development targets on the reserves potential of the Aurora assets; the timing of closing of the asset disposition; the estimated proceeds from the asset disposition; the intended use of the proceeds from the asset disposition; and the results of our asset portfolio review, including the possibility of further asset divestituresour average production rate for the second half of 2014 and full-year 2014; our exploration and development capital expenditures for the second half of 2014 and full-year 2014; our Cliffdale cyclic steam stimulation project, including our assessment of the modified injection and completion strategy; our Gemini steam-assisted gravity drainage project, including our assessment of the performance of the pilot project; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy oil and West Texas Intermediate light oil; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; our ability to mitigate our exposure to heavy oil price differentials by transporting our crude oil to market by railways; the portion of our heavy oil volumes to be transported to market on railways in the third quarter of 2014; our liquidity and financial capacity; the sufficiency of our financial resources to fund our operations; and the target for our total monetary debt to FFO ratio. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time.
These forward-looking statements are based on certain key assumptions regarding, among other things: the receipt of any required approvals for the asset disposition; the satisfaction or waiver of the other conditions to asset disposition; completion of the asset disposition; our ability to execute and realize on the anticipated benefits of the acquisition of Aurora; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the asset disposition may not be completed on the terms contemplated or at all; closing of the asset disposition could be delayed or not completed if we are not able to obtain the necessary approvals required for completion or, unless waived, some other condition to closing is not satisfied; failure to realize the anticipated benefits of the acquisition of Aurora; declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; a downgrade of our credit ratings; the cost of developing and operating our assets; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in government regulations that affect the oil and gas industry; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; depletion of our reserves; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2013, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
The above summary of assumptions and risks related to forward-looking statements in this press release has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations and such information may not be appropriate for other purposes. There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
Non-GAAP Financial Measures
Funds from operations is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Baytex's determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.
Total monetary debt is not a measurement based on GAAP in Canada. Baytex defines total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loans. Baytex believes that this measure assists in providing a more complete understanding of its cash liabilities.
Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to product sales price less royalties, production and operating expenses and transportation expenses divided by barrels of oil equivalent sales volume for the applicable period. Baytex's determination of operating netback may not be comparable with the calculation of similar measures by other entities. Baytex believes that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.
Baytex Energy Corp.
Baytex Energy Corp. is a dividend-paying oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford and Williston Basin in the United States. Approximately 86% of Baytex's production is weighted toward crude oil and natural gas liquids. Baytex pays a monthly dividend on its common shares which are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.
For further information about Baytex, please visit our website at www.baytexenergy.com.
Contacts:
Baytex Energy Corp.
Brian Ector
Senior Vice President, Capital Markets and Public Affairs
Toll Free Number: 1-800-524-5521
investor@baytexenergy.com
