CALGARY, Alberta, July 31, 2018 (GLOBE NEWSWIRE) — Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) reports its operating and financial results for the three and six months ended June 30, 2018 (all amounts are in Canadian dollars unless otherwise noted).
“We continued to deliver on our operational and financial targets in the second quarter, which included strong drilling results in Canada and the Eagle Ford. In addition, we are excited to be moving forward with the proposed merger with Raging River as we unite two strong oil companies with exceptional people and assets. We believe the combined company will deliver a powerful combination of per share production growth and strong free cash flow. We will be well-positioned to optimize our capital investment across our high rate of return asset base,” commented Ed LaFehr, President and Chief Executive Officer.
- Entered into an arrangement agreement with Raging River Exploration Inc. (“Raging River”) to create a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile. This strategic combination is expected to close on August 22, 2018.
- Delivered production of 70,664 boe/d (79% oil and NGL) with exploration and development capital expenditures of $79 million during Q2/2018.
- Generated adjusted funds flow of $107 million ($0.45 per basic share) or $136 million excluding realized financial derivatives gains and losses.
- Realized an operating netback of $35.42/boe in the Eagle Ford, the strongest since Q3/2014. Our Eagle Ford light oil and condensate production received a premium sales price of US$67.62/bbl (or $87.38/bbl) given its proximity to Gulf Coast markets.
- Established average 30-day initial gross production rates of approximately 1,850 boe/d per well from 32 (7.6 net) wells in the Eagle Ford that commenced production in the second quarter. This represents an approximate 25% improvement over wells brought on production in 2017.
- Executed our Q2/2018 drilling program in Canada as planned with production increasing to 34,042 boe/d. Our first two northern Seal wells at Peace River generated 30-day initial production rates of 918 boe/d and 660 boe/d, respectively.
- Expanded our crude by rail volumes to 8,300 bbl/d (33% of our heavy oil production) in Q2/2018. We have secured additional rail capacity, which will see our crude oil volumes delivered to market by rail increase to approximately 9,500 bbl/d in Q3/2018 and 10,500 bbl/d in Q4/2018.
|Three Months Ended
||Six Months Ended
|June 30, 2018
||March 31, 2018||June 30, 2017||June 30, 2018
||June 30, 2017|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||$||347,605||$||286,067||$||277,536||$||633,672||$||538,085|
|Adjusted funds flow (1)||106,690||84,255||83,136||190,945||164,505|
|Per share – basic||0.45||0.36||0.35||0.81||0.70|
|Per share – diluted||0.45||0.36||0.35||0.81||0.70|
|Net income (loss)||(58,761)||(62,722)||9,268||(121,483)||20,364|
|Per share – basic||(0.25)||(0.27)||0.04||(0.51)||0.09|
|Per share – diluted||(0.25)||(0.27)||0.04||(0.51)||0.09|
|Exploration and development||78,830||93,534||78,007||172,364||174,566|
|Acquisitions, net of divestitures||(21)||(2,026)||5,226||(2,047)||71,230|
|Total oil and natural gas capital expenditures||$||78,809||$||91,508||$||83,233||$||170,317||$||245,796|
|Bank loan (2)||$||213,538||$||212,571||$||264,032||$||213,538||$||264,032|
|Long-term notes (2)||1,548,490||1,525,595||1,541,694||1,548,490||1,541,694|
|Working capital (surplus) deficiency||22,807||45,213||13,661||22,807||13,661|
|Net debt (3)||$||1,784,835||$||1,783,379||$||1,819,387||$||1,784,835||$||1,819,387|
|Three Months Ended||Six Months Ended|
|June 30, 2018||March 31, 2018||June 30, 2017||June 30, 2018||June 30, 2017|
|Heavy oil (bbl/d)||25,544||24,868||25,577||25,208||25,104|
|Light oil and condensate (bbl/d)||21,100||20,967||22,370||21,034||21,996|
|Total oil and NGL (bbl/d)||56,063||54,978||57,640||55,523||56,103|
|Natural gas (mcf/d)||87,605||87,261||91,028||87,434||89,771|
|Oil equivalent (boe/d @ 6:1) (4)||70,664||69,522||72,812||70,095||71,065|
|WTI oil (US$/bbl)||67.88||62.87||48.28||65.37||50.10|
|WCS heavy oil (US$/bbl)||48.61||38.59||37.16||43.60||37.25|
|Edmonton par oil ($/bbl)||80.58||72.06||61.92||76.32||62.95|
|LLS oil (US$/bbl)||71.37||67.07||49.70||69.24||51.10|
|Baytex average prices (before hedging)|
|Heavy oil ($/bbl) (5)||49.70||33.33||37.62||41.67||36.81|
|Light oil and condensate ($/bbl)||86.75||79.20||60.68||83.01||61.94|
|Total oil and NGL ($/bbl)||60.56||49.63||44.06||55.18||44.67|
|Natural gas ($/mcf)||2.56||2.95||3.62||2.75||3.57|
|Oil equivalent ($/boe)||51.22||42.96||39.41||47.15||39.77|
|CAD/USD noon rate at period end||1.3142||1.2901||1.2983||1.3142||1.2983|
|CAD/USD average rate for period||1.2911||1.2651||1.3447||1.2781||1.3338|
|COMMON SHARE INFORMATION|
|Share price (Cdn$)|
|Volume traded (thousands)||391,396||177,572||216,383||568,968||472,026|
|Share price (US$)|
|Volume traded (thousands)||175,808||118,236||109,758||294,044||248,931|
|Common shares outstanding (thousands)||236,662||236,578||234,204||236,662||234,204|
- Adjusted funds flow 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 adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to other issuers. We consider adjusted funds flow a key measure of performance as it demonstrates our ability to generate the cash flow necessary to fund capital investments, debt repayment, settlement of our abandonment obligations and potential future dividends. In addition, we use the ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate changes in non-cash working capital and settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. For a reconciliation of adjusted funds flow 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, 2018.
- Principal amount of instruments.
- Net debt is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. We define net debt to be the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes 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.
- We include the cost of blending diluent when calculating our realized heavy oil price.
Strategic Combination with Raging River
On June 18, 2018, Baytex and Raging River announced that their respective boards of directors had unanimously agreed to a strategic combination of the two companies (the “Transaction”). The combined company, which will operate under the Baytex name, will be a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile provided by its world class assets across North America.
The combined company is expected to have production of approximately 94,000 boe/d from a diverse portfolio of high quality oil assets, including Viking, Peace River, Lloydminster and East Duvernay Shale properties in Canada and the Eagle Ford in Texas. The combined company will have a deep inventory of high quality drilling prospects that generate top tier returns on invested capital and have the capability to deliver meaningful organic production growth.
The Transaction will result in holders of common shares of Raging River receiving, directly or indirectly, 1.36 common shares of Baytex for each Raging River Share owned. The Transaction is subject to approval by the shareholders of both companies, the Court of Queen’s Bench of Alberta and certain regulatory and other authorities, and is subject to the satisfaction or waiver of other customary closing conditions.
The joint management information circular was mailed to shareholders of each of Baytex and Raging River on July 20, 2018. Baytex and Raging River shareholders will hold their respective shareholder meetings on August 21, 2018 and the Transaction is expected to close on August 22, 2018. For further information on the Transaction, please see the joint management information circular dated July 12, 2018 and the joint press release dated June 18, 2018.
Our operating results for the second quarter were consistent with our expectations as we continued to deliver on our operational and financial targets. We successfully executed our drilling program with strong results realized in the Eagle Ford and Canada.
Production increased 2% to average 70,664 boe/d (79% oil and NGL) in Q2/2018, as compared to 69,522 boe/d (79% oil and NGL) in Q1/2018. Production in the first half of 2018 averaged 70,095 boe/d. During the second quarter, exploration and development capital expenditures totaled $79 million, bringing the aggregate spending in the first half of 2018 to $172 million. We participated in the drilling of 36 (8.1 net) wells with a 100% success rate during the second quarter.
Our 2018 production guidance range is unchanged at 68,000 to 72,000 boe/d with budgeted exploration and development capital expenditures of $325 to $375 million, and does not include the integration of Raging River, which is expected to close on August 22, 2018. Following closing of the Transaction, Baytex will provide revised guidance for full-year 2018.
Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. The asset generates the highest cash netbacks in our portfolio and contains a significant inventory of development prospects. In Q2/2018, we allocated 61% of our exploration and development expenditures to this asset and production averaged 36,622 boe/d (78% oil and NGL) during the second quarter, as compared to 36,017 boe/d in Q1/2018.
We continue to see strong well performance driven by enhanced completions in Karnes County. In addition, early results from Atascosa County are encouraging as we exploit the oil window on the western portion of our lands. In Q2/2018, we participated in the drilling of 18 (2.6 net) wells, commenced production from 32 (7.6 net) wells and at June 30, 2018 had 70 (18.5 net) wells waiting on completion. The wells that have been on production for more than 30 days established 30-day initial production rates of approximately 1,850 boe/d (65% light oil and condensate), which represents an approximate 25% improvement over wells brought on production in 2017. These wells were completed with approximately 28 effective frac stages per well (compared to 23 in 2015) and proppant per completed foot of approximately 2,100 pounds (compared to 1,100 pounds in 2015).
Our Peace River region, located in northwest Alberta, has been a core asset since we commenced operations in the area in 2004. Through our innovative multi-lateral horizontal drilling and production techniques, we are able to generate some of the strongest capital efficiencies in the oil and gas industry.
Production averaged 16,800 boe/d (92% heavy oil) during the second quarter, as compared to 16,500 boe/d in Q1/2018. In Q2/2018, we drilled one (1.0 net) well and commenced production from four (4.0 net) wells. Our first two northern Seal wells at Peace River generated 30-day initial production rates of 918 boe/d and 660 boe/d, respectively. Approximately 10 wells are anticipated to be drilled in the northern Seal area in 2018. We expect to have a second rig starting up in August as we continue to build operational momentum heading into 2019.
Our Lloydminster region is characterized by multiple stacked pay formations at relatively shallow depths. The area has been successfully developed through vertical and horizontal drilling, water flood, steam-assisted gravity drainage operations and, more recently, the implementation of polymer flooding to further enhance reserves recovery. We have also adopted, where applicable, the multi-lateral well design and geosteering capability that we have successfully utilized at Peace River.
Production averaged 10,300 boe/d (99% heavy oil) during the second quarter as compared to 10,000 boe/d in Q1/2018. We drilled 12 (3.3 net) crude oil wells in Q2/2018. During the second quarter, seven (7.0 net) wells drilled in Q1/2018 established peak 30-day initial production rates of approximately 200 bbl/d per well. In addition, we continued to advance our Kerrobert thermal project. Production at Kerrobert averaged 600 boe/d in H1/2018 and we expect to exit 2018 producing approximately 2,000 boe/d. We recommenced our Soda Lake multi-lateral drilling program in June and expect to have two rigs running in the second half of the year.
We generated adjusted funds flow of $107 million ($0.45 per basic share) in Q2/2018, compared to $84 million ($0.36 per basic share) in Q1/2018 and $83 million ($0.35 per basic share) in Q2/2017. The increase in adjusted funds flow is largely attributable to stronger oil price realizations, partially offset by realized financial derivatives losses.
Excluding realized financial derivatives gains and losses, adjusted funds flow in Q2/2018 was $136 million, compared to $94 million in Q1/2018. This represents the highest quarterly adjusted funds flow (excluding realized financial derivatives gains and losses) since Q4/2014 and demonstrates the strength of our diversified asset portfolio.
We maintain strong financial liquidity with our US$575 million revolving credit facilities approximately 70% undrawn and our first long-term note maturity not until 2021. With our strategy to target exploration and development capital expenditures at a level that approximates our adjusted funds flow, we expect this liquidity position to be stable going forward. In the first six months of 2018, exploration and development capital expenditures totaled $172 million, as compared to adjusted funds flow of $191 million ($230 million excluding realized financial derivatives losses).
On April 25, 2018, we extended the maturity of our revolving credit facilities by one year to June 2020. These facilities are covenant-based and do not require annual or semi-annual reviews. We are well within the financial covenants on these facilities as our Senior Secured Debt to Bank EBITDA ratio as at June 30, 2018 was 0.6:1.0, compared to a maximum permitted ratio of 3.5:1.0, and our interest coverage ratio was 4.1:1.0, compared to a minimum required ratio of 2.0:1.0.
Our net debt totaled $1.78 billion at June 30, 2018, which is down from $1.82 billion at June 30, 2017.
Our operating netback (excluding realized financial derivatives gains and losses) improved 48% to $27.08/boe in Q2/2018, as compared to $18.30/boe in Q2/2017. During the second quarter, we benefited from continued strong liquids pricing in the Eagle Ford and improved heavy oil price realizations in Canada. The Eagle Ford generated an operating netback of $35.42/boe during Q2/2018 while our Canadian operations generated an operating netback of $18.12/boe.
In Q2/2018, the price for West Texas Intermediate light oil (“WTI”) averaged US$67.88/bbl, as compared to US$48.28/bbl in Q2/2017. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$19.27/bbl in Q2/2018, as compared to US$11.12/bbl in Q2/2017.
In the Eagle Ford, our assets are proximal to Gulf Coast markets with light oil and condensate production priced off the Louisiana Light Sweet (“LLS”) crude oil benchmark, which is a function of the Brent price. In Q2/2018, the price for LLS averaged US$71.37/bbl, as compared to US$49.70/bbl in Q2/2017. During the second quarter, our light oil and condensate realized price in the Eagle Ford of US$67.62/bbl (or $87.38/bbl) represented a US$3.75/bbl discount to LLS.
The following table summarizes our operating netbacks for the periods noted.
|Three Months Ended June 30|
|($ per boe except for sales volume)||Canada||U.S.||Total
|Sales volume (boe/d)||34,042||36,622||70,664||34,284||38,528||72,812|
|Total sales, net of blending and other expense||$||41.61||$||60.16||$||51.22||$||33.86||$||44.34||$||39.41|
|Realized financial derivatives (loss) gain||—||—||(4.57)||—||—||0.40|
|Operating netback after financial derivatives (loss) gain||$||18.12||$||35.42||$||22.51||$||11.71||$||24.14||$||18.70|
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 adjusted funds flow. We realized a financial derivatives loss of $29 million in Q2/2018 due to the increased price of crude oil relative to the prices set in our contracts. A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2018 financial statements.
As part of our risk management program, we also transport crude oil to markets by rail when economics warrant. In Q2/2018, we delivered 8,300 bbl/d (approximately 33%) of our heavy oil volumes to market by rail, up from 6,500 bbl/d in Q1/2018. We have secured additional rail capacity, which will see our crude oil volumes delivered to market by rail increase to approximately 9,500 bbl/d in Q3/2018 and 10,500 bbl/d in Q4/2018. We have also successfully commenced the re-contracting of future year crude by rail commitments, which to-date total 7,500 bbl/d for 2019 and 5,000 bbl/d for 2020.
The following table summarizes our 2018 annual guidance and compares it to our 2018 year-to-date actual results. Following closing of the strategic combination with Raging River, we will provide revised guidance for the combined company.
|Exploration and development capital ($ millions)||325 – 375||172.4||–||%|
|Production (boe/d)||68,000 – 72,000||70,095||–||%|
|Royalty rate (%)||~ 23.0||23.7||1||%|
|Operating ($/boe)||10.50 – 11.25||10.72||–||%|
|Transportation ($/boe)||1.35 – 1.45||1.29||(4)||%|
|General and administrative ($ millions)||~ 44 (1.72/boe)||21.6 (1.70/boe)||(1)||%|
|Interest ($ millions)||~ 100 (3.95/boe)||50.0 (3.94/boe)||–||%|
- As announced on December 7, 2017.
Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2018 and the 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 31, 2018, starting at 9:00am MDT (11:00am EDT). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq220180731.html in your web browser.
An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.