CALGARY, ALBERTA — (Marketwired) — 08/14/13 — Baytex Energy Corp. (“Baytex”) (TSX: BTE)(NYSE: BTE) reports its operating and financial results for the three and six months ended June 30, 2013 (all amounts are in Canadian dollars unless otherwise noted).
Commenting on the results, James Bowzer, President and Chief Executive Officer of Baytex, said: “Our operational execution remains on track. We grew production in the second quarter by 12% to over 58,000 boe/d, which represents the highest quarterly production rate in company history. Our funds from operations of $155.8 million represents the second highest level of quarterly FFO.”
Summary
“We expect continued strong operating and financial results in the second half of this year,” said Bowzer. “In recognition of this, we are tightening our production guidance range for 2013 from the previously disclosed range of 56,000-58,000 boe/d to 57,000-58,000 boe/d.”
Operations Review
Production averaged 58,236 boe/d (87% oil and NGL) during Q2/2013, an increase of 12% over Q1/2013. Capital expenditures for exploration and development activities totaled $177.8 million and included the drilling of 33 (25.8 net) wells with a 100% success rate. In addition, we continued to progress our thermal development with facility construction now underway at both our Cliffdale 15-well cyclic steam stimulation module and our steam-assisted gravity drainage pilot project at Angling Lake.
In recognition of our strong operating results to-date, we are tightening our production guidance range for 2013 from the previously disclosed range of 56,000-58,000 boe/d to 57,000-58,000 boe/d. Consistent with previous guidance, exploration and development expenditures for 2013 are forecast to be approximately $520 million, which includes $90 million for long-term thermal projects. Our production mix for 2013 is forecast to be 75% heavy oil, 14% light oil and NGL and 11% natural gas.
Heavy Oil
In Q2/2013, heavy oil production averaged 42,510 bbl/d, an increase of 13% over Q1/2013. During Q2/2013, we drilled 23 (20.6 net) oil wells with a success rate of 100%.
Production from our Peace River area properties averaged approximately 23,000 bbl/d in Q2/2013, an increase of 22% over Q1/2013. In the second quarter of 2013, we drilled 17 (17.0 net) cold horizontal producers in the Peace River area bringing our year-to-date drilling to 23 (23.0 net) wells. Of the 23 wells drilled during the first half of 2013, 22 wells have established average 30-day peak production rates of approximately 700 bbl/d. We plan to drill approximately 14 multi-lateral horizontal wells in the remainder of 2013.
Successful operations continued at our Cliffdale 10-well cyclic steam stimulation (“CSS”) module with Q2/2013 production averaging approximately 400 bbl/d. During the second quarter, fifth cycle steaming operations commenced on the initial Cliffdale pilot well with production flowback start-up in mid-June. Current production from the Cliffdale CSS project is approximately 700 bbl/d. Facility construction at our new Cliffdale 15-well CSS module is well underway with drilling operations commencing in Q2/2013. We expect to complete construction of the plant and commence cold production in Q4/2013. First cycle steaming of the wells is expected to occur in the first half of 2014.
In our Lloydminster heavy oil area, Q2/2013 drilling included four (1.6 net) horizontal oil wells and two (2.0 net) vertical oil wells. During Q1/2013, we drilled one (1.0 net) thermal infill well at our Kerrobert steam-assisted gravity drainage (“SAGD”) project. This well commenced production in Q2/2013 adding incremental production of approximately 400 bbl/d. We plan to drill approximately 50 net wells in the Lloydminster area in the remainder of 2013, including one thermal infill well and one SAGD well pair at Kerrobert.
At Angling Lake, construction of the Gemini SAGD pilot project facilities commenced late in Q2/2013. Construction of the drilling pad is complete, mechanical crews have been mobilized and major equipment is being moved onsite. We expect to drill the SAGD well pair during the third quarter and are on track for steaming late this year or early 2014.
Light Oil & Natural Gas
During Q2/2013, light oil, NGL and natural gas production increased 9% over Q1/2013 to 15,726 boe/d, which was comprised of 8,202 bbl/d of light oil and NGL and 45.1 mmcf/d of natural gas.
In our Bakken/Three Forks play in North Dakota, we drilled eight (4.5 net) operated horizontal oil wells and fracture-stimulated 10 (5.1 net) operated wells in Q2/2013. During Q2/2013, nine Baytex-operated wells on 1,280-acre spacing established average 30-day peak production rates of approximately 360 boe/d. We plan to drill approximately two (1.0 net) wells on our Bakken/Three Forks play in North Dakota in the remainder of 2013.
Financial Review
We generated FFO of $155.8 million ($1.26 per basic share) in Q2/2013, which was the second highest level of quarterly FFO in company history. This represents a 53% increase from the $101.8 million generated in Q1/2013. This increase was the result of higher sales volumes and higher realized commodity prices. During the second quarter, our operating netback (sales price less royalties, production and operating expenses and transportation expenses) of $31.71/boe represented an improvement of 27% over Q1/2013.
The average WTI price for Q2/2013 was US$94.22/bbl, essentially unchanged from Q1/2013. The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 20% in Q2/2013, as compared to 34% in Q1/2013. Factors that caused heavy oil differentials to narrow included heavy oil supply shortfalls, declines in Canadian crude storage levels, increases in rail shipments and the return of refineries from maintenance. As a result of narrower heavy oil differentials, our realized average oil and NGL price of $66.17/bbl in Q2/2013 (inclusive of our physical hedging gains) increased by 14% from $58.00/bbl in Q1/2013.
We have taken advantage of the recent strength in WTI prices and the weaker Canadian dollar to add to our hedge portfolio. For the second half of 2013, we have entered into hedges on approximately 63% of our WTI exposure at a weighted average price of US$99.33/bbl, 42% of our exposure to WCS heavy oil differentials through a combination of long term physical supply contracts and rail delivery, 54% 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 second quarter, approximately 17,000 bbl/d of our heavy oil volumes were delivered to market by rail, as compared to 7,500 bbl/d for full-year 2012. For Q3/2013, we expect to deliver approximately 20,000 bbl/d of our heavy oil volumes by rail, and we continue to explore additional opportunities for rail deliveries.
Royalty rates in Q2/2013 were approximately 19.3% of sales revenues before sales of purchased condensate. We expect royalty rates to average approximately 20-21% for full-year 2013 as a result of certain oil sands projects reaching payout and farm-in agreements.
Total monetary debt at the end of Q2/2013 was $770.5 million, representing a debt-to-FFO ratio of 1.2 times based on Q2/2013 FFO annualized. At the end of the second quarter, Baytex had $624.6 million in undrawn credit facilities and no long-term debt maturities until 2021. During the second quarter, we increased the amount of our credit facilities by $150 million to $850 million and extended the maximum term of the facilities by one year to four years. With our capital spending program weighted toward the first half of the year, and assuming continued strength in production levels and commodity prices, we expect that total debt levels will reduce over the balance of 2013.
Additional Information
Our unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2013 and related Management–s Discussion and Analysis of the operating and financial results can be accessed immediately on our website at and will be available shortly through SEDAR at and EDGAR at .
Conference Call Today
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call today, August 14, 2013, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-8061 or toll free in North America 1-866-225-0198 and toll free international 1-800-6578-9898. Alternatively, to listen to the conference call online, please enter in your web browser.
An archived recording of the conference call will be available until August 21, 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 1399715. The conference call will also be archived on the Baytex website at .
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 operating and financial results in the second half of 2013; our average production rate for 2013; our exploration and development capital expenditures for 2013; our production mix 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 steam and flowback 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 a steam-assisted gravity drainage pilot project at Angling Lake, including the timing of construction of the pilot facilities, drilling of the pilot well pair 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 ability to access the U.S. Gulf Coast market by transporting crude oil on rail; 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 market by rail; the volume of heavy oil to be transported to market on rail for the third quarter of 2013; our average royalty rate for full-year 2013; our debt-to-FFO ratio; the amount of our undrawn credit facilities at June 30, 2013; our liquidity and financial capacity; and the potential to reduce total debt levels over the balance of 2013. 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 Generally Accepted Accounting Principles (“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 revenue less royalties, production and operating expenses and transportation expenses dividend 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 .
Contacts:
Baytex Energy Corp.
Brian Ector
Vice President, Investor Relations
Toll Free Number: 1-800-524-5521