CALGARY, ALBERTA--(Marketwired - July 30, 2015) - Baytex Energy Corp. ("Baytex") (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2015 (all amounts are in Canadian dollars unless otherwise noted).
"Given the current low crude oil price environment, we remain focused on prudently managing our operations to maintain strong levels of financial liquidity. The execution of our capital program has yielded impressive results in the Eagle Ford as we advance the multi-zone development potential of our acreage with 11 multi-zone projects in various stages of execution and production. In Canada, our assets continue to perform as expected with limited capital investment. Through negotiated cost savings with service providers, our portfolio of development opportunities in the Eagle Ford, Peace River and Lloydminster continue to provide attractive returns," commented James Bowzer, President and Chief Executive Officer.
Highlights
- Generated production of 84,812 boe/d (82% oil and NGL) in Q2/2015;
- Delivered funds from operations ("FFO") of $158.0 million ($0.77 per share) in Q2/2015;
- Realized an operating netback (sales price less royalties, production and operating expenses, and transportation expenses) in Q2/2015 of $20.66/boe ($25.85/boe including financial derivative gains);
- Advanced the multi-zone development potential of our Eagle Ford acreage with 30-day initial production rates per well ranging from 900 to 1,600 boe/d for two projects that targeted three separate horizons;
- Maintained a conservative payout ratio, net of participation in our dividend reinvestment plan ("DRIP"), of 24% (39% before DRIP) in Q2/2015; and
- Completed an equity financing on April 2, 2015, raising net proceeds of approximately $606 million which were applied to reduce outstanding indebtedness.
| Three Months Ended | Six Months Ended | |||||||||||||
| June 30, 2015 |
March 31, 2015 |
June 30, 2014 |
June 30, 2015 |
June 30, 2014 |
||||||||||
| FINANCIAL(thousands of Canadian dollars, except per common share amounts) | ||||||||||||||
| Petroleum and natural gas sales | $ | 345,432 | $ | 285,615 | $ | 476,404 | $ | 631,047 | $ | 862,213 | ||||
| Funds from operations (1) | 158,049 | 160,221 | 165,503 | 318,270 | 336,312 | |||||||||
| Per share - basic | 0.77 | 0.95 | 1.22 | 1.70 | 2.57 | |||||||||
| Per share - diluted | 0.77 | 0.95 | 1.21 | 1.70 | 2.54 | |||||||||
| Cash dividends declared (2) | 37,908 | 41,466 | 75,397 | 79,375 | 138,838 | |||||||||
| Dividends declared per share | 0.30 | 0.30 | 0.68 | 0.60 | 1.34 | |||||||||
| Net income (loss) | (26,955 | ) | (175,916 | ) | 36,799 | (202,871 | ) | 84,640 | ||||||
| Per share - basic | (0.13 | ) | (1.04 | ) | 0.27 | (1.08 | ) | 0.65 | ||||||
| Per share - diluted | (0.13 | ) | (1.04 | ) | 0.27 | (1.08 | ) | 0.64 | ||||||
| Exploration and development | 106,010 | 147,429 | 148,916 | 253,439 | 321,341 | |||||||||
| Acquisitions, net of divestitures | 1,170 | 1,550 | 2,920,845 | 2,720 | 2,921,518 | |||||||||
| Total oil and natural gas capital expenditures | $ | 107,180 | $ | 148,979 | $ | 3,069,761 | $ | 256,159 | $ | 3,242,859 | ||||
| Bank loan(3) | $ | 192,255 | $ | 780,447 | $ | 952,402 | $ | 192,255 | $ | 952,402 | ||||
| Long-term debt(3) | 1,493,013 | 1,513,002 | 1,329,487 | 1,493,013 | 1,329,487 | |||||||||
| Working capital deficiency | 137,243 | 162,546 | 178,517 | 137,243 | 178,517 | |||||||||
| Total monetary debt (4) | $ | 1,822,511 | $ | 2,455,995 | $ | 2,460,406 | $ | 1,822,511 | $ | 2,460,406 | ||||
| OPERATING | ||||||||||||||
| Daily production | ||||||||||||||
| Heavy oil (bbl/d) | 35,439 | 39,261 | 45,986 | 37,339 | 45,611 | |||||||||
| Light oil and condensate (bbl/d) | 25,899 | 28,056 | 9,865 | 26,971 | 7,680 | |||||||||
| NGL (bbl/d) | 8,232 | 8,224 | 2,475 | 8,228 | 2,232 | |||||||||
| Total oil and NGL (bbl/d) | 69,570 | 75,541 | 58,326 | 72,538 | 55,523 | |||||||||
| Natural gas (mcf/d) | 91,456 | 91,010 | 51,645 | 91,234 | 46,295 | |||||||||
| Oil equivalent (boe/d @ 6:1) (5) | 84,812 | 90,710 | 66,934 | 87,744 | 63,239 | |||||||||
| Benchmark prices | ||||||||||||||
| WTI oil (US$/bbl) | 57.94 | 48.64 | 102.99 | 53.29 | 100.84 | |||||||||
| WCS heavy oil (US$/bbl) | 46.35 | 33.91 | 82.95 | 40.14 | 79.25 | |||||||||
| Edmonton par oil ($/bbl) | 67.72 | 51.94 | 106.68 | 59.84 | 103.43 | |||||||||
| LLS oil (US$/bbl) | 62.38 | 50.55 | 106.81 | 56.47 | 105.86 | |||||||||
| Baytex average prices (before hedging) | ||||||||||||||
| Heavy oil ($/bbl) (6) | 44.59 | 28.57 | 79.26 | 36.21 | 75.26 | |||||||||
| Light oil and condensate ($/bbl) | 65.11 | 52.34 | 104.16 | 58.50 | 101.20 | |||||||||
| NGL ($/bbl) | 15.78 | 19.35 | 38.74 | 17.55 | 46.34 | |||||||||
| Total oil and NGL ($/bbl) | 48.82 | 36.40 | 81.74 | 42.39 | 77.68 | |||||||||
| Natural gas ($/mcf) | 3.06 | 3.22 | 4.84 | 3.14 | 5.01 | |||||||||
| Oil equivalent ($/boe) | 43.34 | 33.54 | 75.06 | 38.30 | 71.92 | |||||||||
| CAD/USD noon rate at period end | 1.2474 | 1.2683 | 1.0676 | 1.2474 | 1.0676 | |||||||||
| CAD/USD average rate for period | 1.2294 | 1.2308 | 1.0894 | 1.2353 | 1.0964 | |||||||||
| COMMON SHARE INFORMATION | ||||||||||||||
| TSX | ||||||||||||||
| Share price (Cdn$) | ||||||||||||||
| High | 24.14 | 24.87 | 49.88 | 24.87 | 49.88 | |||||||||
| Low | 19.24 | 16.03 | 44.30 | 16.03 | 38.90 | |||||||||
| Close | 19.43 | 20.03 | 45.89 | 20.03 | 45.89 | |||||||||
| Volume traded (thousands) | 80,572 | 122,179 | 45,952 | 202,752 | 99,733 | |||||||||
| NYSE | ||||||||||||||
| Share price (US$) | ||||||||||||||
| High | 20.10 | 19.99 | 46.30 | 19.99 | 46.30 | |||||||||
| Low | 15.42 | 13.14 | 40.70 | 13.14 | 35.34 | |||||||||
| Close | 15.58 | 15.80 | 42.16 | 15.8 | 42.16 | |||||||||
| Volume traded (thousands) | 44,497 | 24,213 | 3,552 | 68,710 | 7,702 | |||||||||
| Common shares outstanding (thousands) | 206,193 | 169,001 | 165,421 | 206,193 | 165,421 | |||||||||
Notes:
- 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, 2015.
- Cash dividends declared are net of DRIP participation.
- Principal amount of instruments.
- 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)) and the principal amount of both the long-term debt and the bank loan.
- 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.
- Heavy oil prices exclude condensate blending.
Operations Review
During the second quarter, we continued to execute our 2015 capital program as planned and our results are consistent with expectations. In response to the weakness in commodity prices, our overall level of capital spending was lower for the third consecutive quarter as we deferred activity in Canada and reduced activity in the Eagle Ford. Reflective of this reduced activity, production averaged 84,812 boe/d (82% oil and NGL) in Q2/2015 as compared to 90,710 boe/d in Q1/2015. Capital expenditures for exploration and development activities totaled $106.0 million in Q2/2015, down from $147.4 million in Q1/2015, and $214.7 million in Q4/2014. In Q2/2015, we participated in the drilling of 51 (15.2 net) wells with a 100% success rate.
One of our key attributes is our portfolio of projects with strong capital efficiencies and high rates of return. Through negotiated cost savings with service providers, our portfolio of development opportunities in the Eagle Ford, Peace River and Lloydminster continue to provide attractive returns in today's low crude oil price environment.
Our 2015 production guidance remains at 84,000 to 88,000 boe/d with budgeted exploration and development expenditures of $500 to $575 million. Our 2015 capital program remains flexible and allows for adjustments to second half spending based on changes in the commodity price environment.
Wells Drilled - Three Months Ended June 30, 2015
| Stratigraphic | Dry and | ||||||||||
| Crude Oil | Natural Gas | and Service | Abandoned | Total | |||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||
| Heavy oil | |||||||||||
| Lloydminster | 2 | 2.0 | - | - | - | - | - | - | 2 | 2.0 | |
| Peace River | - | - | - | - | - | - | - | - | - | - | |
| 2 | 2.0 | - | - | - | - | - | - | 2 | 2.0 | ||
| Light oil and natural gas | |||||||||||
| Eagle Ford | 12 | 3.4 | 37 | 9.8 | - | - | - | - | 49 | 13.2 | |
| Western Canada | - | - | - | - | - | - | - | - | - | - | |
| 12 | 3.4 | 37 | 9.8 | - | - | - | - | 49 | 13.2 | ||
| Total | 14 | 5.4 | 37 | 9.8 | - | - | - | - | 51 | 15.2 | |
Wells Drilled - Six Months Ended June 30, 2015
| Stratigraphic | Dry and | ||||||||||
| Crude Oil | Natural Gas | and Service | Abandoned | Total | |||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||
| Heavy oil | |||||||||||
| Lloydminster | 9 | 5.1 | - | - | - | - | - | - | 9 | 5.1 | |
| Peace River | 1 | 1.0 | - | - | 5 | 5.0 | - | - | 6 | 6.0 | |
| 10 | 6.1 | - | - | 5 | 5.0 | - | - | 15 | 11.1 | ||
| Light oil and natural gas | |||||||||||
| Eagle Ford | 48 | 10.8 | 67 | 17.6 | - | - | 2 | 0.6 | 117 | 29.1 | |
| Western Canada | - | - | - | - | - | - | - | - | - | - | |
| 48 | 10.8 | 67 | 17.6 | - | - | 2 | 0.6 | 117 | 29.1 | ||
| Total | 58 | 16.9 | 67 | 17.6 | 5 | 5.0 | 2 | 0.6 | 132 | 40.2 | |
U.S. Operations
Production in the Eagle Ford averaged 39,548 boe/d (79% oil and NGL) during Q2/2015, as compared to 41,076 boe/d in Q1/2015 and 38,035 boe/d in Q4/2014. Capital expenditures in the Eagle Ford in Q2/2015 totaled $98.3 million, down from $126.2 million in Q1/2015 and $149.5 million in Q4/2014. This reduction is reflective of reduced activity levels combined with negotiated cost savings with service providers.
We continued to scale back our activity during the second quarter as we adjust to the lower crude oil pricing environment. We reduced the number of drilling rigs on our lands from 12 in late 2014 to five currently. In addition, the number of frac crews has been reduced from three in late 2014 to one or two currently.
During the second quarter, 40 (11.6 net) wells were brought onstream, as compared to 52 (13.2 net) wells during the first quarter. Of the 40 wells that commenced production during the second quarter, 27 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,200 boe/d. As at June 30, 2015, we had 83 (20.3 net) wells awaiting completion.
In addition to targeting the Lower Eagle Ford formation, we are now actively delineating the Austin Chalk formation. The number of wells on our lands producing from the Austin Chalk is now 37 (10.7 net) with an average 30-day initial production rate of approximately 1,000 boe/d.
Additional advancements have been made to delineate the multi-zone development potential of our Sugarkane acreage. We have initiated "stack and frac" pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk. Recent production data from two pads (a total of nine wells) that targeted three zones achieved 30-day initial production rates per well ranging from 900 to 1,600 boe/d. We now have eleven multi-zone projects in various stages of execution and production.
Canadian Operations
Production in Canada averaged 45,264 boe/d (85% oil and NGL) during Q2/2015, as compared to 49,634 boe/d in Q1/2015. The reduced volumes in Canada are a result of lower drilling activity, the decommissioning of our Gemini steam-assisted gravity drainage pilot project and uneconomic production that we have shut-in. Capital expenditures for our Canadian assets in Q2/2015 totaled $7.7 million, down from $21.3 million in Q1/2015.
At Lloydminster, we drilled two (2.0 net) horizontal wells. At Peace River, no drilling occurred in Q2/2015. During the quarter, the commissioning of Phase One of the Genalta Peace River Power Centre was completed resulting in Baytex delivering approximately 3.5 mmcf/d of natural gas to the facility for the purpose of generating electricity. In Q3/2015, Phase Two of the project is anticipated to be commissioned, resulting in the conservation of an additional 0.7 mmcf/d of natural gas and total electrical generation equivalent to the needs of over 23,000 homes in Alberta.
Financial Review
We generated FFO of $158.0 million ($0.77 per share) in Q2/2015, compared to $160.2 million ($0.95 per share) in Q1/2015. The variance is largely due to a decrease in realized financial derivative gains of $61.7 million, offset by higher revenues associated with improved commodity prices. During the second quarter, we funded 100% of our exploration and development expenditures and cash dividends with funds from operations. We recorded a net loss in Q2/2015 of $27.0 million ($0.13 per share) compared to a net loss of $175.9 million ($1.04 per share) in Q1/2015. The reduction in our net loss is largely due to higher revenues associated with improved commodity prices combined with a reversal of some of the negative movements on our U.S. dollar denominated debt due to a modest strengthening of the Canadian dollar in Q2/2015 after a significant weakening in Q1/2015.
In Q2/2015, we experienced an improvement in commodity prices with our realized oil and NGL price increasing 20% to $43.68/bbl, versus $36.40/bbl in Q1/2015. The average price for West Texas Intermediate ("WTI") increased to US$57.94/bbl during the quarter, as compared to US$48.64/bbl in Q1/2015 and the discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, narrowed to US$11.59/bbl in Q2/2015, as compared to US$14.73/bbl in Q1/2015. Subsequent to quarter-end, WCS differentials have widened with the August index averaging US$13.41/bbl. We expect WCS differentials to narrow in the coming months as improved market access is expected to reduce current inventory levels. The premium for Louisiana Light Sweet crude oil ("LLS"), relative to WTI, also widened to US$4.44/bbl in Q2/2015, as compared to US$1.91/bbl in Q1/2015.
We recognized a $0.6 million recovery of current income tax expense in Q2/2015. Through the first six months of 2015, we have recognized current income tax expense of $16.4 million. We forecast cash income taxes in 2015 at an effective tax rate of approximately 3-5% of pre-tax funds from operations. Substantially all of our estimated current income tax expense for 2015 has been recognized in the first half of 2015.
We generated an operating netback in Q2/2015 of $20.66/boe ($25.85/boe including financial derivatives gains). Our Canadian operations generated an operating netback of $16.48/boe while the Eagle Ford generated an operating netback of $25.45/boe. Our Eagle Ford assets are located in south Texas and are proximal to Gulf Coast crude oil markets with established transportation systems, resulting in strong realized prices. Our light oil and condensate production in the Eagle Ford is priced primarily off a LLS benchmark which typically trades at a premium to WTI. This strong pricing, combined with low cash costs, contributed positively to our operating netback in Q2/2015. The table below provides a summary of our operating netbacks for the periods noted.
| Three Months Ended June 30, 2015 |
Three Months Ended June 30, 2014 |
|||||
| ($ per boe) | Canada | Eagle Ford | Total | Change | ||
| Sales Price | $40.43 | $46.67 | $43.34 | $75.06 | (42)% | |
| Less: | ||||||
| Royalties | 6.87 | 13.79 | 10.10 | 18.36 | (45)% | |
| Production and operating expenses | 13.45 | 7.43(1) | 10.64 | 12.51 | (15)% | |
| Transportation expenses | 3.63 | - | 1.94 | 3.45 | (44)% | |
| Operating netback | $16.48 | $25.45 | $20.66 | $40.74 | (48)% | |
| Financial derivatives gain (loss) | - | - | 5.19 | (2.28) | -% | |
| Operating netback after financial derivatives | $16.48 | $25.45 | $25.85 | $38.46 | (32)% | |
| (1) In the Eagle Ford, transportation expenses are included in production and operating expenses. | ||||||
Risk Management
We employ a comprehensive risk management program which is intended to reduce some of the volatility in our FFO. In Q2/2015, we realized financial derivatives gains of $40.1 million, primarily due to crude oil prices being at levels significantly below those set in our fixed price contracts, which were partially offset by the settlement of our out-of-money foreign exchange contracts.
For Q3/2015, we have entered into hedges on approximately 24% of our net WTI exposure with 17% fixed at US$79.86/bbl and 7% receiving WTI plus US$10.00/bbl when WTI is below US$80.00/bbl. The unrealized financial derivatives gain with respect to our WTI hedges as at June 30, 2015 was $45.7 million. The following table summarizes our WTI hedges in place as at July 29, 2015.
| Q3/2015 | Q4/2015 | Last 6 Months 2015 |
Full-Year 2016 |
|
| Fixed Hedges | ||||
| Volumes (bbl/d) | 8,000 | 9,000 | 8,500 | 6,250 |
| Hedge (%) (1) | 17% | 19% | 18% | 13% |
| Price (US$/bbl) | $79.86 | $78.25 | $79.01 | $63.64 |
| Floating Hedges | ||||
| Volumes (bbl/d) | 3,312 | - | 1,656 | - |
| Hedge (%) (1) | 7% | - | 4% | - |
| Price (US$/bbl) (2) | WTI + $10.00 | - | WTI + $10.00 | - |
| Total Hedge Volume | ||||
| Volumes (bbl/d) | 11,312 | 9,000 | 10,156 | 6,250 |
| Hedge (%) (1) | 24% | 19% | 22% | 13% |
| (1) Percentage of hedged volumes is based on the mid-point of our 2015 production guidance (excluding NGL), net of royalties. | ||||
| (2) Hedges reflect our exposure when WTI is less than US$80/bbl. | ||||
As part of our hedging program, we also focus on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to markets by rail when economics warrant. We have no fixed investment or take or pay obligations to transport crude oil by rail and infrastructure around our core heavy oil producing regions allows for optimization between rail and pipe. In Q2/2015, approximately 18,000 bbl/d of our heavy oil volumes were delivered to market by rail, down 18% from the previous quarter. For Q3/2015, we expect to deliver approximately 15,000 bbl/d of our heavy oil volumes to market by rail as we optimize our heavy oil netbacks.
Financial Liquidity
We have taken several steps to maintain strong levels of financial liquidity this year, including evaluating our level and timing of capital spending, negotiating cost savings with service providers and completing an equity financing. On April 2, 2015, we issued 36,455,000 common shares at a price of $17.35 per share for net proceeds of approximately $606 million, which were used to reduce bank indebtedness.
Total monetary debt at June 30, 2015 was $1.82 billion, comprised of a bank loan of $192 million, long-term debt of $1.49 billion, and a working capital deficiency of $137 million. The decrease in total monetary debt at June 30, 2015, as compared to March 31, 2015, was primarily due to the application of the net proceeds from the equity financing to the bank loan.
We have unsecured revolving credit facilities consisting of a $1.0 billion Canadian facility and a US$200 million U.S. facility. During the second quarter, we extended the maturity date of these facilities to June 2019 (from June 2018 previously). These facilities do not require any mandatory principal payments prior to maturity and can be further extended beyond June 2019 with the consent of the lenders. As at June 30, 2015, we had approximately $1.05 billion in undrawn capacity on these facilities.
Amendments made to the financial covenants contained in our unsecured revolving credit facilities in February 2015 provide us with increased financial flexibility. As at June 30, 2015, our Senior Debt (1) to Bank EBITDA (2) ratio (twelve months trailing) is 1.72:1.00. Our revised financial covenants allow this ratio to reach a maximum of 4.75:1.00 through June 2016 and 4.50:1.00 through December 2016.
- "Senior debt" is defined as the sum of the principal amount of our bank loan and long-term debt.
- Bank EBITDA is a non-GAAP measure calculated based on terms and definitions set out in the credit agreement which adjusts net income for financing costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, amortization, impairment, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange, and share-based compensation) and acquisition and disposition activity and is calculated based on a trailing twelve month basis.
Additional Information
Our unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2015 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.
| Conference Call Today 9:00 a.m. MDT (11:00 a.m. EDT) |
| Baytex will host a conference call today, July 30, 2015, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-8527 or toll free in North America 1-800-396-7098 and toll free international 1-800-6578-9868. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/6621 in your web browser. An archived recording of the conference call will be available until August 6, 2015 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 9111441. The conference call will also be archived on the Baytex website at http://www.baytexenergy.com/. |
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 business strategies, plans and objectives; our annual average production rate for 2015; our capital budget for 2015; our plan for developing our properties in 2015, including the number and type of wells and the geographic location of wells; our Eagle Ford shale play, including initial production rates from new wells, our plans to use "stack and frac" pilots to target three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation and our assessment of the results of our "stack and frac" pilots; the timing of completion of the second phase of Genalta's Peace River Power Centre, the additional volumes of natural gas to be conserved and the amount of electricity to be generated; the outlook for the price differential between Western Canadian Select heavy oil and West Texas Intermediate light oil; our expectation regarding the payment of cash income taxes in 2015, including our effective tax rate; 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 on railways; the volume of heavy oil to be transported to market on railways in the third quarter of 2015; our liquidity and financial capacity; and the sufficiency of our financial resources to fund our operations. 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: our ability to execute and realize on the anticipated benefits of the acquisition of the Eagle Ford assets; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserves 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). The reader is 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 volatility of oil and natural gas prices; substantial or extended declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; uncertainties in the capital markets that may restrict the availability of or increase the cost of capital or of borrowing; refinancing risk for existing debt and the risk of failing to comply with covenants in existing debt agreements; risks associated with properties operated by third parties, specifically with respect to a substantially majority of our Eagle Ford assets; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all hazards associated with acquiring, developing and exploring for oil and natural gas; business risks; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; 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, 2014, 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 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.
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
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. We define 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)) and the principal amount of both the long-term debt and the bank loan. We believe that this measure assists in providing a more complete understanding of our 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 for other entities. Baytex believes that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.
Payout ratio is defined as cash dividends (net of participation in our dividend reinvestment plan) divided by funds from operations. We believe that this measure assists in providing a more complete understanding of certain aspects of our results of operations and financial performance, including our ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments.
Advisory Regarding Oil and Gas Information
Where applicable, oil equivalent 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.
References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.
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 in the United States. Approximately 82% 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.
Contact Information:
Brian Ector
Senior Vice President, Capital Markets and Public Affairs
Toll Free Number: 1-800-524-5521
investor@baytexenergy.com
www.baytexenergy.com