Baytex Energy Corp.
TSX : BTE
NYSE : BTE

Baytex Energy Corp.

October 30, 2013 08:00 ET

Baytex Reports Record Production and Funds From Operations for Third Quarter 2013

CALGARY, ALBERTA--(Marketwired - Oct. 30, 2013) - Baytex Energy Corp. ("Baytex") (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three and nine months ended September 30, 2013 (all amounts are in Canadian dollars unless otherwise noted).

Commenting on the results, James Bowzer, President and Chief Executive Officer, said: "We had an exceptional quarter. We grew production in the third quarter by 3% to over 60,000 boe/d as compared to Q2/2013 and 11% as compared to Q3/2012. This represents the highest quarterly production rate in company history. In addition, our funds from operations of $199.3 million represents the highest level of quarterly FFO in company history."

Summary

  • Generated record quarterly production of 60,184 boe/d (89% oil and NGL) in Q3/2013, an increase of 3% over Q2/2013;
  • Generated funds from operations ("FFO") of $199.3 million ($1.61 per basic share) during Q3/2013, the highest level of quarterly FFO in our history and an increase of 28% over Q2/2013;
  • Earned net income of $87.3 million, or $0.70 per share, an increase of 141% over Q2/2013;
  • Produced approximately 26,000 bbl/d from our Peace River area properties in Q3/2013, an increase of 13% over Q2/2013;
  • Continued to progress our thermal development with facility construction on time and on budget at both our 15-well CSS module at Cliffdale and our Gemini SAGD pilot project;
  • Realized an operating netback (sales price less royalties, production and operating expenses and transportation expenses) in Q3/2013 of $42.14/boe, an increase of 33% over Q2/2013; and
  • Ended the third quarter with total monetary debt of $756.6 million, representing a debt-to-FFO ratio of 1.3 times based on FFO over the trailing twelve-month period.
Three Months Ended Nine Months Ended
September 30, 2013 June 30,
2013
September 30, 2012 September 30, 2013 September 30, 2012
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales 422,791 341,011 299,786 1,036,747 927,389
Funds from operations (1) 199,318 155,804 139,044 456,894 405,472
Per share - basic 1.61 1.26 1.15 3.71 3.39
Per share - diluted 1.59 1.25 1.14 3.66 3.34
Cash dividends declared (2) 61,354 60,328 52,640 178,129 160,142
Dividends declared per share 0.66 0.66 0.66 1.98 1.98
Net income 87,331 36,192 26,773 133,672 227,011
Per share - basic 0.70 0.29 0.22 1.08 1.90
Per share - diluted 0.70 0.29 0.22 1.07 1.87
Exploration and development 121,484 177,834 113,126 465,840 351,939
Acquisitions, net of divestitures 2,838 (1,796 ) 2,160 (41,340 ) (302,733 )
Total oil and natural gas capital expenditures 124,322 176,038 115,286 424,500 49,206
Bank loan 244,651 225,434 181,785 244,651 181,785
Long-term debt 454,275 457,680 447,555 454,275 447,555
Working capital deficiency (surplus) 57,703 87,418 (149,329 ) 57,703 (149,329 )
Total monetary debt (3) 756,629 770,532 480,011 756,629 480,011
Three Months Ended Nine Months Ended
September 30, 2013 June 30,
2013
September 30, 2012 September 30, 2013 September 30, 2012
OPERATING
Daily production
Light oil and NGL (bbl/d) 8,366 8,202 7,047 8,163 7,233
Heavy oil (bbl/d) 44,908 42,510 40,580 41,664 39,176
Total oil and NGL (bbl/d) 53,274 50,712 47,627 49,827 46,409
Natural gas (mcf/d) 41,460 45,148 40,524 41,979 43,336
Oil equivalent (boe/d @ 6:1) (4) 60,184 58,236 54,381 56,823 53,633
Average prices (before hedging)
WTI oil (US$/bbl) 105.82 94.22 92.22 98.15 96.20
WCS heavy oil (US$/bbl) 88.34 75.07 70.50 75.29 74.20
Edmonton par oil ($/bbl) 105.07 92.94 84.79 95.55 87.29
Baytex light oil and NGL ($/bbl) 88.63 77.85 70.34 81.23 74.80
Baytex heavy oil ($/bbl) (5) 79.29 63.92 60.11 66.41 61.12
Baytex total oil and NGL ($/bbl) 80.75 66.17 61.63 68.83 63.25
Baytex natural gas ($/mcf) 2.72 3.59 2.34 3.26 2.26
Baytex oil equivalent ($/boe) 73.36 60.42 55.70 62.77 56.56
CAD/USD noon rate at period end 1.0285 1.0512 0.9837 1.0285 0.9837
CAD/USD average rate for period 1.0385 1.0231 0.9953 1.0236 1.0023
COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
High 44.44 43.05 50.37 47.60 59.40
Low 37.65 36.37 39.91 36.37 38.54
Close 42.51 37.90 46.72 42.51 46.72
Volume traded (thousands) 24,658 30,085 25,679 82,511 83,219
NYSE
Share price (US$)
High 43.08 42.50 51.73 47.47 59.50
Low 35.72 34.71 39.50 34.75 37.40
Close 41.27 36.04 47.44 41.27 47.44
Volume traded (thousands) 3,282 4,763 5,823 11,414 18,568
Common shares outstanding (thousands) 124,497 123,593 120,962 124,497 120,962
Notes:
(1) Funds from operations is a non-Generally Accepted Accounting Principles ("GAAP") measure that represents cash generated 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 nine months ended September 30, 2013.
(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)), 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 are net of blending costs.

Operations Review

Production averaged 60,184 boe/d (89% oil and NGL) during Q3/2013, an increase of 3% over Q2/2013. Capital expenditures for exploration and development activities totaled $121.5 million and included the drilling of 76 (58.3 net) wells with a 98% success rate. In addition, we continued to progress our thermal development with facility construction on time and on budget at both our 15-well cyclic steam stimulation ("CSS") module at Cliffdale and our Gemini steam-assisted gravity drainage ("SAGD") pilot project.

Our third quarter operating results are the strongest in company history. We previously tightened our production guidance following the second quarter of 2013. In recognition of our operational performance, we are further tightening our guidance range for 2013 to 57,500 to 58,000 boe/d, up from previous guidance of 57,000 to 58,000 boe/d and original guidance of 56,000 to 58,000 boe/d.

Given that we expect to achieve the upper end of our original production guidance range, and as we look to maintain our positive operating momentum into 2014, we plan to increase our original 2013 exploration and development budget of $520 million by approximately 5%. The incremental capital will be directed toward our Peace River, Lloydminster and North Dakota operating regions with production additions occurring in Q1/2014. We are in the process of setting our 2014 capital budget, the details of which are expected to be released on December 13, 2013, following approval by our Board of Directors.

Wells Drilled - Three Months Ended September 30, 2013

Crude Oil
Stratigraphic Dry and
Primary Thermal Natural Gas and Service Abandoned Total
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Heavy oil
Lloydminster area 47 31.0 3 3.0 - - 3 3.0 1 1.0 54 38.0
Peace River area 7 7.0 10 10.0 - - 1 1.0 - - 18 18.0
54 38.0 13 13.0 - - 4 4.0 1 1.0 72 56.0
Light oil, NGL and natural gas
Western Canada - - - - 1 1.0 - - - - 1 1.0
North Dakota 3 1.3 - - - - - - - - 3 1.3
3 1.3 - - 1 1.0 - - - - 4 2.3
Total 57 39.3 13 13.0 1 1.0 4 4.0 1 1.0 76 58.3

Wells Drilled - Nine Months Ended September 30, 2013

Crude Oil
Stratigraphic Dry and
Primary Thermal Natural Gas and Service Abandoned Total
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Heavy oil
Lloydminster area 120 92.3 4 4.0 - - 3 3.0 2 2.0 129 101.3
Peace River area 30 30.0 10 10.0 - - 31 31.0 - - 71 71.0
150 122.3 14 14.0 - - 34 34.0 2 2.0 200 172.3
Light oil, NGL and natural gas
Western Canada 14 11.0 - - 2 2.0 - - - - 16 13.0
North Dakota 18 8.6 - - - - - - - - 18 8.6
32 19.6 - - 2 2.0 - - - - 34 21.6
Total 182 141.9 14 14.0 2 2.0 34 34.0 2 2.0 234 193.9

Heavy Oil

In Q3/2013, heavy oil production averaged 44,908 bbl/d, an increase of 6% over Q2/2013. During Q3/2013, we drilled 67 (51.0 net) oil wells, four (4.0 net) stratigraphic and service wells, and one (1.0 net) dry and abandoned well on our heavy oil properties.

Production from our Peace River area properties averaged approximately 26,000 bbl/d in Q3/2013, an increase of 13% over Q2/2013. In Q3/2013, we drilled seven (7.0 net) cold horizontal producers in the Peace River area bringing our year-to-date drilling to 30 (30.0 net) wells. Of the 30 wells drilled during the first nine months of 2013, 28 wells have established average 30-day peak production rates of approximately 700 bbl/d. We plan to drill approximately 10 multi-lateral horizontal wells in the remainder of 2013.

Successful operations continued at our 10-well CSS module at Cliffdale with Q3/2013 production averaging 600 bbl/d. Facility construction at our new 15-well CSS module at Cliffdale is proceeding on schedule with commissioning activities now underway and production facility startup planned for Q4/2013, while steam facility commissioning will occur in Q1/2014. Drilling operations are nearing completion and we expect to commence cold production from the first five of the fifteen wells in Q4/2013.

Recently the Alberta Energy Regulator announced plans to hold a public proceeding that will investigate concerns about odours and emissions associated with heavy oil production in the Peace River area. We welcome this proceeding which will provide an additional opportunity for us to engage with the public about our operations in the area and our efforts to minimize environmental impacts. Baytex has made significant investments to enhance its operations and will continue to operate in an environmentally responsible manner for the benefit of all stakeholders.

In our Lloydminster heavy oil area, Q3/2013 drilling included 21 (11.4 net) horizontal oil wells and 27 (20.6 net) vertical oil wells, with a 97% success rate, and one (1.0 net) thermal infill well and one (1.0 net) SAGD well pair at our Kerrobert SAGD project. The new SAGD well pair commenced production in September and established a 30-day peak production rate of 900 bbl/d. We plan to drill approximately 15 net wells in the Lloydminster area in the remainder of 2013.

Construction of the Gemini SAGD pilot project facilities continued in Q3/2013 and we drilled the pilot SAGD well pair. We remain on track for steaming late this year or early 2014.

Light Oil & Natural Gas

During Q3/2013, natural gas production decreased 8% from Q2/2013 to 41.5 mmcf/d as we focused our activity on higher rate of return oil investment opportunities. Light oil and NGL production increased 2% over Q2/2013 to 8,366 bbl/d.

In our Bakken/Three Forks play in North Dakota, we drilled three (1.3 net) horizontal oil wells and fracture-stimulated four (2.3 net) wells in Q3/2013. During Q3/2013, six Baytex-operated wells on 1,280-acre spacing established average 30-day peak production rates of approximately 470 boe/d.

Financial Review

We generated FFO of $199.3 million ($1.61 per basic share) in Q3/2013, which was the highest level of quarterly FFO in company history, demonstrating the cash flow generating capacity of the company in a strong heavy oil pricing environment. This record level of FFO was achieved notwithstanding that the Company had a net realized loss on financial derivative contracts of $19.7 million. Q3/2013 FFO represents a 28% increase from the $155.8 million generated in Q2/2013 and was the result of higher sales volumes and higher realized commodity prices. During Q3/2013, our operating netback (sales price less royalties, production and operating expenses and transportation expenses) of $42.14/boe represented an improvement of 33% over Q2/2013.

The average WTI price for Q3/2013 was US$105.82/bbl, a 12% increase from Q2/2013. The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 17% in Q3/2013, as compared to 20% in Q2/2013. Factors driving a stronger WCS price differential in the third quarter of 2013 included peak demand for heavy oil driven by seasonal product and asphalt demand, and increased volumes of heavy oil being transported by rail which pulled heavy oil supply away from traditional Canadian heavy oil markets. Our realized average oil and NGL price of $80.75/bbl in Q3/2013 (inclusive of our physical hedging gains) increased by 22% from $66.17/bbl in Q2/2013.

We have taken advantage of the recent strength in WTI prices and the weaker Canadian dollar to add to our hedge portfolio. For Q4/2013, we have entered into hedges on approximately 67% of our WTI exposure at a weighted average price of US$99.56/bbl, 46% of our exposure to WCS price differentials primarily through a combination of long term physical supply contracts and rail delivery, 47% of our natural gas price exposure, and 51% of our exposure to currency movements between the U.S. and Canadian dollars. Details of our hedging contracts are contained in the notes to our financial statements.

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 third quarter, approximately 20,000 bbl/d of our heavy oil volumes were delivered to market by rail, as compared to 7,500 bbl/d for full-year 2012 and 15,000 bbl/d for the first half of 2013. For Q4/2013, we expect to deliver approximately 23,0000 to 24,000 bbl/d of our heavy oil volumes by rail, and we continue to explore additional opportunities for rail deliveries.

Royalty rates in Q3/2013 were approximately 20.5% of sales revenues before sales of purchased condensate, consistent with our expectations of 20-21% for full-year 2013. Royalty rates have increased in 2013 as a result of higher commodity prices which impact sliding scale royalty rates, certain oil sands projects reaching payout, and obligations under certain farm-in agreements.

During Q3/2013, we recorded a recovery of cash income taxes of $6.6 million. This is a partial recovery of the income tax paid in 2012 on the disposition of certain of our North Dakota assets. We do not expect to incur any cash income tax expense nor receive any additional tax refund in Q4/2013.

Total monetary debt at the end of Q3/2013 was $756.6 million, representing a debt-to-FFO ratio of 1.3 times based on FFO over the trailing twelve-month period. At the end of the third quarter, Baytex had $605.3 million in undrawn credit facilities and no long-term debt maturities until 2021. Baytex continues to have a strong balance sheet and ample liquidity to allow us execute our growth and income model.

As part of normal course business, we maintain a base shelf prospectus on file with securities regulatory authorities in both Canada and the United States to provide us with ready access to the capital markets in the event that we require external financing. On October 25, 2013, we filed a base shelf prospectus which allows us to issue equity and debt securities with an aggregate offering amount not to exceed $750 million (Canadian) at any time during the ensuing 25-month period. Our previously filed base shelf prospectus expired in September 2013.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2013 and related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytex.ab.ca and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Today
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call today, October 30, 2013, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-2216 or toll free in North America 1-866-226-1792 and toll free international 1-800-9559-6849. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/4867 in your web browser.
An archived recording of the conference call will be available until November 6, 2013 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 1277788. The conference call will also be archived on the Baytex website at http://www.baytex.ab.ca/.

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: our average production rate for 2013; our exploration and development capital expenditures for 2013; development plans for our properties, including the number of wells to be drilled in the remainder of 2013 and, in some cases, when such wells will commence production; initial production rates from wells drilled; our Peace River heavy oil area, including our assessment of the productivity of recently drilled horizontal wells; our Cliffdale cyclic steam stimulation project, including our assessment of the operations for the initial 10-well module and our plan for a second module, including the timing of drilling the wells, completing plant construction, commencing cold production and commencing steam injection; our plans for the Gemini steam-assisted gravity drainage pilot project, including the timing of construction of the pilot facilities and commencing steam injection; 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 the volatility in heavy oil price differentials by transporting our crude oil to higher value markets by rail; the volume of heavy oil to be transported to market on rail for the fourth quarter of 2013; our average royalty rate for full-year 2013; our debt-to-FFO ratio; the amount of our undrawn credit facilities at September 30, 2013; and our liquidity and financial capacity. 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: 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; 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; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period 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: 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; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; 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 properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities;
risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; 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 the control of Baytex. These 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, 2012, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast 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 Williston Basin in the United States. Approximately 89% of Baytex's production is weighted toward crude oil. 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.baytex.ab.ca.

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