Baytex Energy Corp.
TSX : BTE
NYSE : BTE

Baytex Energy Corp.

November 02, 2016 07:30 ET

Baytex Reports Q3 2016 Results

CALGARY, ALBERTA--(Marketwired - Nov. 2, 2016) - Baytex Energy Corp. ("Baytex") (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three and nine months ended September 30, 2016 (all amounts are in Canadian dollars unless otherwise noted).

"We are increasing our full year 2016 production guidance by 2% on the back of our strong third quarter operating results and planned activity levels through year-end. For the second consecutive quarter our funds from operations exceeded capital expenditures resulting in a reduction in net debt. Production in Canada increased 6% over the second quarter as we received the full benefit of restored production from previously shut-in heavy oil wells, while production in the Eagle Ford was lower, reflective of a reduced pace of development and the sale of our operated assets. We are well positioned to benefit from a rising oil price environment with strong capital efficiencies across our three core resource plays," commented James Bowzer, Chief Executive Officer.

Highlights

  • Generated production of 67,167 boe/d (78% oil and NGL) in Q3/2016;
  • Delivered funds from operations ("FFO") of $72.1 million ($0.34 per share) in Q3/2016;
  • Reduced net debt by $79 million in Q3/2016 and by $186 million year-to-date;
  • Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q3/2016 of $13.91/boe ($16.95/boe including financial derivatives gain);
  • Reduced operating expenses by 12% to $9.31/boe in the nine months ended September 30, 2016, as compared to $10.55/boe for same period last year;
  • Maintained strong levels of financial liquidity with a Senior Secured Debt to Bank EBITDA ratio of 0.79:1.00; and
  • Completed minor non-core asset sales totaling approximately $63 million.
Three Months Ended Nine Months Ended
September 30, 2016 June 30,
2016
September 30, 2015 September 30, 2016 September 30, 2015
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales $ 197,648 $ 195,733 $ 265,876 $ 546,979 $ 892,062
Funds from operations (1) 72,106 81,261 105,052 199,012 423,322
Per share - basic 0.34 0.39 0.51 0.94 2.18
Per share - diluted 0.34 0.39 0.51 0.94 2.18
Net income (loss) (39,430 ) (86,937 ) (519,247 ) (125,760 ) (723,705 )
Per share - basic (0.19 ) (0.41 ) (2.50 ) (0.60 ) (3.73 )
Per share - diluted (0.19 ) (0.41 ) (2.50 ) (0.60 ) (3.73 )
Exploration and development 39,579 35,490 126,804 156,754 380,243
Acquisitions, net of divestitures (62,752 ) (37 ) (498 ) (62,798 ) 2,222
Total oil and natural gas capital expenditures $ (23,173 ) $ 35,453 $ 126,306 $ 93,953 $ 382,465
Bank loan(2) $ 289,859 $ 347,083 $ 208,195 $ 289,859 $ 208,195
Long-term notes(2) 1,554,510 1,544,181 1,581,002 1,554,510 1,581,002
Long-term debt 1,844,369 1,891,264 1,789,197 1,844,369 1,789,197
Working capital deficiency 19,653 51,274 160,539 19,653 160,539
Net debt (3) $ 1,864,022 $ 1,942,538 $ 1,949,736 $ 1,864,022 $ 1,949,736
Three Months Ended Nine Months Ended
September 30, 2016 June 30,
2016
September 30, 2015 September 30, 2016 September 30, 2015
OPERATING
Daily production
Heavy oil (bbl/d) 24,132 22,423 33,639 23,789 36,067
Light oil and condensate (bbl/d) 19,001 21,894 24,712 21,785 26,210
NGL (bbl/d) 9,149 9,834 8,507 9,695 8,322
Total oil and NGL (bbl/d) 52,282 54,151 66,858 55,269 70,599
Natural gas (mcf/d) 89,314 95,281 91,869 94,253 91,448
Oil equivalent (boe/d @ 6:1) (4) 67,167 70,031 82,170 70,978 85,840
Benchmark prices
WTI oil (US$/bbl) 44.94 45.60 46.43 41.34 51.00
WCS heavy oil (US$/bbl) 31.44 32.29 33.13 27.66 37.80
Edmonton par oil ($/bbl) 54.80 54.78 56.22 50.14 58.63
LLS oil (US$/bbl) 45.82 46.20 49.79 41.76 54.24
Baytex average prices (before hedging)
Heavy oil ($/bbl) (5) 29.79 30.09 30.90 23.91 34.54
Light oil and condensate ($/bbl) 53.25 52.42 55.46 47.27 57.54
NGL ($/bbl) 14.96 13.28 15.35 15.58 16.79
Total oil and NGL ($/bbl) 35.72 36.07 38.00 31.65 42.39
Natural gas ($/mcf) 2.95 1.94 3.28 2.42 3.19
Oil equivalent ($/boe) 31.73 30.52 34.59 27.86 37.10
CAD/USD noon rate at period end 1.3117 1.3009 1.3394 1.3117 1.3394
CAD/USD average rate for period 1.3051 1.2885 1.3094 1.3228 1.2631
COMMON SHARE INFORMATION
TSX
Share price (Cdn$)
High 7.72 9.04 19.50 9.04 24.87
Low 4.76 4.85 3.92 1.57 3.92
Close 5.57 7.50 4.27 5.57 4.27
Volume traded (thousands) 377,435 466,201 165,674 1,326,946 368,426
NYSE
Share price (US$)
High 6.18 7.14 15.51 7.14 20.10
Low 3.59 3.67 2.92 1.08 2.92
Close 4.25 5.79 3.20 4.25 3.20
Volume traded (thousands) 168,984 198,514 109,902 521,550 178,612
Common shares outstanding (thousands) 211,542 210,715 210,225 211,542 210,225
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 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 capital investments and potential future dividends. 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, 2016.
(2) Principal amount of instruments.
(3) Net 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 current financial derivatives, assets held for sale, onerous contracts and liabilities related to assets held for sale)) and the principal amount of both the long-term notes and the 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.

Third Quarter Results

As we entered 2016, we laid out certain strategic objectives to help guide us through the commodity price downturn, which included deploying capital efficiently, continuing to emphasize cost reductions across all facets of our organization and maintaining strong levels of financial liquidity. Our third quarter results were reflective of these strategic objectives and we remain well positioned to benefit from a continued recovery in crude oil prices. We highlight below some of the results achieved to-date from the execution of these initiatives.

Operating Results

Our operating results for the third quarter were consistent with our full-year plans, with production averaging 67,167 boe/d (78% oil and NGL) in Q3/2016, as compared to 70,031 boe/d in Q2/2016. We continued to curtail our level of capital spending, focusing all development activity in the Eagle Ford. In Q3/2016, our exploration and development expenditures totaled $39.6 million, as compared to $35.5 million in Q2/2016 and $81.7 million in Q1/2016.

In the Eagle Ford, our pace of completions through the first nine months of 2016 was down approximately 21% compared to the first nine months of 2015. This reduced pace of completions, combined with the previously announced divestiture of our operated assets in the Eagle Ford, contributed to production averaging 33,552 boe/d in Q3/2016, as compared to 38,309 boe/d in Q2/2016. Year-to-date, we have participated in the drilling of 100 gross (29.5 net) wells in the Eagle Ford and commenced production from 84 gross (24.7 net) wells, as compared to the first nine months of 2015 where we participated in the drilling of 149 gross (38.4 net) wells and commenced production from 123 gross (31.3 net) wells.

We continue to advance our completion activity in the Eagle Ford with increased frac stages and proppant usage. During the third quarter, we averaged 2-3 drilling rigs and 1-2 completion crews on our lands. We participated in the drilling of 18 gross (5.7 net) wells in the Eagle Ford and commenced production from 30 gross (8.8 net) wells. Of the 30 wells that commenced production during the third quarter, 15 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,350 boe/d.

In Canada, we reinitiated production during the second quarter from heavy oil wells that were shut-in earlier this year. The full benefit of bringing these shut-in volumes back online was realized during the third quarter, which led to a 6% increase in Canadian production to 33,615 boe/d, as compared to 31,722 boe/d in Q2/2016.

Cost Reductions

We continue to have success in reducing our cost structure while maintaining safety and efficiency in our operations.

Costs in the Eagle Ford have continued to decrease with wells now being drilled, completed and equipped for approximately US$5.2 million, as compared to US$8.2 million in late 2014. The prevailing commodity price environment has not supported drilling on our Canadian assets in 2016. However, we continue to actively build on the 20% cost reductions achieved in 2015 and strengthen the size and quality of our prospect inventory.

Operating expenses have been reduced by 12% to $9.31/boe in the first nine months of 2016, as compared to $10.55/boe for the same period in 2015. These cost reductions reflect a combination of a lower overall cost structure in Canada and our lower cost Eagle Ford assets representing a larger percentage of our total production. Transportation expenses are also down, averaging $1.05/boe through the first nine months of 2016, as compared to $1.81/boe for the same period in 2015.

General and administrative expenses for the three and nine months ended September 30, 2016 of $12.1 million and $38.5 million, respectively, decreased from $14.0 million and $46.6 million for the same periods in 2015. The decrease is attributable to reductions in staffing levels combined with cost saving initiatives.

Financial Liquidity

We have targeted our capital expenditures to approximate our funds from operations to minimize additional bank borrowings. In Q3/2016, our funds from operations totaled $72.1 million, as compared to capital expenditures of $39.6 million, and in the first nine months of 2016, our funds from operations totaled $199.0 million, as compared to capital expenditures of $156.8 million.

Our net debt (bank loan, long-term notes and working capital deficiency) has decreased to $1.86 billion at September 30, 2016 from $2.05 billion at December 31, 2015.

On March 31, 2016, we amended our credit facilities to provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our banking syndicate first priority security over our assets and restructuring our financial covenants. The revolving credit facilities, which currently mature in June 2019, are not borrowing base facilities and do not require annual or semi-annual reviews. Our Senior Secured Debt to Bank EBITDA ratio as at September 30, 2016 was 0.79:1.00 (maximum permitted ratio of 5.00:1.00) and our interest coverage ratio was 3.62:1.00 (minimum required ratio of 1.25:1.00).

Operating Netback

During the third quarter, our operating netback was largely unchanged as compared to Q2/2016. In Q3/2016, the price for West Texas Intermediate light oil ("WTI") averaged US$44.94/bbl, as compared to US$45.60/bbl in Q2/2016, while the discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, averaged US$13.50/bbl in Q3/2016, as compared to US$13.31/bbl in Q2/2016.

We generated an operating netback in Q3/2016 of $13.91/boe ($16.95/boe including financial derivatives gain), as compared to $14.39/boe ($18.13/boe including financial derivatives gain) in Q2/2016. The Eagle Ford generated an operating netback of $20.24/boe during Q3/2016 while our Canadian operations generated an operating netback of $7.59/boe.

The following table provides a summary of our operating netbacks for the periods noted.

Three Months Ended September 30
2016 2015
($ per boe except for volume) Canada U.S. Total Canada U.S. Total
Sales volume (boe/d) 33,615 33,552 67,167 43,229 38,941 82,170
Oil and natural gas revenues $ 26.52 $ 36.95 $ 31.73 $ 29.06 $ 40.72 $ 34.59
Less:
Royalties 3.85 10.89 7.37 3.88 11.74 7.61
Operating expenses 12.32 5.82 9.07 12.31 7.97 10.25
Transportation expenses 2.76 - 1.38 2.88 - 1.52
Operating netback $ 7.59 $ 20.24 $ 13.91 $ 9.99 $ 21.01 $ 15.21
Realized financial derivatives gain - - 3.04 - - 3.33
Operating netback after financial derivatives gain $ 7.59 $ 20.24 $ 16.95 $ 9.99 $ 21.01 $ 18.54

Risk Management

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our FFO. We realized a financial derivatives gain of $18.8 million in Q3/2016 due to crude oil and natural gas prices being at levels below those in our financial derivative contracts.

For the fourth quarter of 2016, we have entered into hedges on approximately 45% of our net WTI exposure with 15% fixed at US$63.79/bbl and 30% hedged utilizing a 3-way option structure that provide us with downside price protection at approximately US$50/bbl and upside participation to approximately US$60/bbl. We have also entered into hedges on approximately 41% of our net WCS differential exposure and 65% of our net natural gas exposure.

For 2017, we have entered into hedges on approximately 44% of our net WTI exposure utilizing a 3-way option structure that provide us with downside price protection at approximately US$47/bbl and upside participation to approximately US$59/bbl. We have also entered into hedges on approximately 24% of our net WCS differential exposure and 49% of our net natural gas exposure.

A complete listing of our financial derivative contracts can be found in Note 15 to our Q3/2016 financial statements.

Disposition Activity

On July 27, 2016, we closed the previously announced disposition of our operated assets in the Eagle Ford for net proceeds of $54.6 million. At the time of disposition, these assets were producing approximately 1,000 boe/d and included reserves of approximately 1.26 million boe on a proved plus probable basis (as evaluated by Ryder Scott Company, L.P. at December 31, 2015). In addition, we have disposed of an additional 650 boe/d of certain non-core assets in Canada. We do not anticipate any further asset sales at this time.

Guidance

We are revising upward our full year 2016 production guidance range to 69,000 to 70,000 boe/d (previously 67,000 to 69,000 boe/d). We anticipate our full year 2016 exploration and development capital expenditures will be toward the high end of our guidance of $200 to $225 million. At this level of spending and based on the forward strip for crude oil and natural gas, we expect our funds from operations to exceed capital expenditures in 2016.

In the Eagle Ford, we are currently running 4 drilling rigs and 2 completion crews on our lands. We expect this level of activity to continue into 2017. We have also commenced preliminary work in advance of a 2017 development program in Canada, including lease construction and surveying.

We are in the process of setting our 2017 capital budget, the details of which are expected to be released in December following approval by our Board of Directors.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2016 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, November 2, 2016, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-2218 or toll free in North America 1-866-225-0198 and toll free international 1-800-6578-9868. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/8224 in your web browser.
An archived recording of the conference call will be available until November 14, 2016 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 2742607. 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 but not limited to: our business plan, strategies and objectives, including to deploy capital efficiently, emphasize cost reductions and maintain strong levels of financial liquidity; that we are well positioned to benefit from a continued oil price recovery and that our three core plays provide strong capital efficiencies; our Eagle Ford shale play, including our assessment of the performance of wells drilled in Q3/2016 and the cost to drill, complete and equip a well; our ability to continue to reduce our cost structure; our target for 2016 capital expenditures to approximate funds from operations in order to minimize additional bank borrowings; our ability to partially reduce the volatility in our funds from operations by utilizing financial derivative contracts for commodity prices, heavy oil differentials and interest and foreign exchange rates; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in reducing the volatility in our funds from operations; our expectations for annual average production rate and exploration and development capital expenditures for 2016; that we expect funds from operations to exceed capital expenditures in 2016; and our expectation that current activity levels in the Eagle Ford for drilling and completions will continue into 2017. 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.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; 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; 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 volatility of oil and natural gas prices; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; depletion of our reserves; 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 risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; 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, 2015, 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 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.

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 flow from operating activities adjusted for 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 capital investments and potential future dividends to shareholders. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.

Net debt is not a measurement based on GAAP in Canada. We define net debt as the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives, assets held for sale, onerous contracts and liabilities related to assets held for sale)) and the principal amount of both the long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.

Bank EBITDA is not a measurement based on GAAP in Canada. We define Bank EBITDA as our consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items as set out in the credit agreement governing our revolving credit facilities. This measure is used to measure compliance with certain financial covenants.

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 divided by barrels of oil equivalent sales volume for the applicable period. Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

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 an 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 78% of Baytex's production is weighted toward crude oil and natural gas liquids. Baytex's common shares trade 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.

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