Drilling & Completions | Rig Count | Production | Proppant | Initial Production Rates-30-Day | Capital Expenditure | Capex Decrease

Baytex Trims Capex for 2017; Shifts Eagle Ford Focus to Oil Window

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   |    Tuesday,August 01,2017

[Summary: Baytex released its Q2 results and praised its production efforts in Eagle Ford while simultaneously decreasing its capital expenditure guidance from $325 to $350 million to $310 to $330 million or about a -2% change.

Eagle Ford

Baytex directed 76% of its capex toward Karnes County acreage in the Eagle Ford during Q2. The Eagle Ford acreage produced 38,500 boe/d, or an increase of 7% from Q1. The company averaged five rigs with about one to two completion crews.

Baytex has shifted its focus from the condensate window to the oil window in the Eagle Ford. Its three recently completed Karnes County pads (11 wells) located in the oil window of the Longhorn acreage, established 30-day initial production rates of approximately 2,150 boe/d per well. Each pad was completed with 30 frac stages per well and proppant per completed foot of ~1,900 pounds, which is more than double the frac intensity of wells previously drilled in the area. 



Additionally, Baytex had a well cost ranging between $4.7 and 4.9 million, which is slightly below the $5 million cost the company initially assumed in its 2017 budget.

At the end of the quarter, Baytex had 51 (13 net) wells awaiting completion

Murphy Asset

Baytex purchased a Murphy asset earlier in 2017. The company reduced the operating cost 30% and is currently seeing production rates of 3,500 bo/d, up from 3,000 to 3,300 bo/d.] 



ORIGINAL RELEASE


CALGARY, Alberta, Aug. 01, 2017 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2017 (all amounts are in Canadian dollars unless otherwise noted).

"Driven by excellent capital efficiencies across our portfolio, we have been able to substantially grow production largely within funds from operations during the first half of the year at US$50/bbl oil prices. This is due to some of the strongest well results we have seen to-date in the Eagle Ford and a safe and highly efficient start-up of our development program in Canada. Our team is pushing to reposition the business for success at these low commodity prices with production currently above the high end of guidance and capital expenditures tracking toward the low end of guidance," commented Ed LaFehr, President and Chief Executive Officer.

Highlights

  • Generated production of 72,812 boe/d (79% oil and NGL) during Q2/2017, an increase of 5% from Q1/2017 and 12% from Q4/2016;
  • Delivered funds from operations ("FFO") of $83.1 million ($0.35 per basic share) in Q2/2017 and $164.5 million ($0.70 per basic share) in H1/2017;
  • Produced 38,528 boe/d in the Eagle Ford, an increase of 7% from Q1/2017 and 15% from Q4/2016, and 34,284 boe/d in Canada, an increase of 3% from Q1/2017 and 8% from Q4/2016;
  • Established average 30-day initial gross production rates of approximately 2,150 boe/d per well from three recently completed pads (total of 11 wells) in the oil window of our Eagle Ford acreage;
  • Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q2/2017 of $18.30/boe ($18.70/boe including financial derivatives gain);
  • Reduced annual guidance for operating expenses by 4% (at mid-point) to $10.75-$11.25/boe, reflecting strong performance in H1/2017 of $10.50/boe; and
  • Tightened our 2017 production guidance range to 69,000 to 70,000 boe/d (previously 68,000 to 70,000 boe/d) and exploration and development capital expenditures to $310 to $330 million (previously $325 to $350 million).

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Operating Results

Our operating results for the second quarter reflect strong drilling results and an increased pace of activity in the Eagle Ford that began late in Q4/2016, the resumption of drilling activity in Canada and a full quarter contribution from the Peace River acquisition, which closed on January 20, 2017.

Production increased 5% to average 72,812 boe/d (79% oil and NGL) in Q2/2017, as compared to 69,298 boe/d (79% oil and NGL) in Q1/2017. Production in the first half of 2017 averaged 71,065 boe/d. During the second quarter, exploration and development capital expenditures totaled $78.0 million, bringing the aggregate spending in the first half of 2017 to $174.6 million. We participated in the drilling of 47 (15.3 net) wells with a 100% success rate during the second quarter.

Reflective of our strong operating results in the first half of the year, we are tightening our 2017 production guidance range to 69,000 to 70,000 boe/d (previously 68,000 to 70,000 boe/d). We are now forecasting full-year 2017 exploration and development capital expenditures of $310 to $330 million (previously $325 to $350 million). We are also reducing our guidance for operating expenses by 4% (at the mid-point) to $10.75-$11.25/boe as we continue to drive cost efficiencies in our business.

We will continue to employ a flexible approach to prudently manage our capital program as we target exploration and development capital expenditures at a level that approximates our funds from operations.

Eagle Ford

Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. The assets generate the highest cash netbacks in our portfolio and contain a significant inventory of development prospects. In Q2/2017, we directed 76% of our exploration and development expenditures toward these assets.

Production increased 7% during the second quarter to average 38,528 boe/d (77% liquids), as compared to 36,081 boe/d in Q1/2017. During the second quarter, we averaged 4-5 drilling rigs and 1-2 completion crews on our lands. In Q2/2017, we participated in the drilling of 38 (9.4 net) wells and commenced production from 35 (8.1 net) wells. At quarter end, we had 51 (13.0 net) wells waiting on completion.

We continue to see strong well performance driven by enhanced completions in the oil window of our acreage with the cost to drill, complete, equip and tie-in a well of US$4.74.9 million. The wells that commenced production during the quarter have established 30-day initial gross production rates of approximately 1,500 boe/d per well. Our three recently completed Karnes City pads (total of 11 wells) within the oil window of our Longhorn acreage established 30-day initial gross production rates of approximately 2,150 boe/d per well. These pads were completed with approximately 30 effective frac stages per well and proppant per completed foot of approximately 1,900 pounds, which is more than double the frac intensity of wells previously drilled in the area.

Peace River

Our Peace River region, located in northwest Alberta, has been a core asset for us 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 increased 8% during the second quarter to average 18,300 boe/d (93% heavy oil), as compared to 17,000 boe/d in Q1/2017. The production increase was driven by an active drilling program combined with a full quarter contribution from the Peace River acquisition, which closed on January 20, 2017.

We drilled 4 (4.0 net) wells during the second quarter and 7 (7.0 net) wells during the first six months of 2017. Six of the wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 400 bbl/d per well and two of these wells ranked among the top oil wells drilled in Alberta during this period.

Lloydminster

Our Lloydminster region, which straddles the Alberta and Saskatchewan border, is characterized by multiple stacked pay formations at relatively shallow depths, which we have successfully developed through vertical and horizontal drilling, water flood and steam-assisted gravity drainage operations.

Production averaged approximately 8,600 boe/d (98% heavy oil) during the second quarter, as compared to 9,100 boe/d in Q1/2017. The reduced volumes reflect a lower pace of development activity during the second quarter due to spring break-up. We drilled 5 (1.9 net) wells during the second quarter and 22 (14.9 net) wells during the first six months of 2017.

Financial Review

We generated FFO of $83.1 million ($0.35 per share) in Q2/2017, compared to $81.4 million ($0.35 per share) in Q1/2017. The increase in FFO is largely due to higher production volumes, which more than mitigated the decline in crude oil prices. FFO in the first half of 2017 totaled $164.5 million ($0.70 per share), compared to $126.9 million ($0.60 per share) in the first half of 2016.

Financial Liquidity

We continue to maintain strong financial liquidity as our US$575 million revolving credit facilities are approximately two-thirds undrawn and our first meaningful long-term note maturity is not until 2021. With our strategy to target exploration and development capital expenditures at a level that approximates our funds from operations, we expect this liquidity position to be stable going forward.

Our revolving credit facilities, which currently mature in June 2019, are covenant-based and do not require annual or semi-annual reviews. We are well within our financial covenants on these facilities as our Senior Secured Debt to Bank EBITDA ratio as at June 30, 2017 was 0.7:1.0, compared to a maximum permitted ratio of 5.0:1.0, and our interest coverage ratio was 4.0:1.0, compared to a minimum required ratio of 1.25:1.0.

Our net debt totaled $1.8 billion at June 30, 2017, which is down $123 million from June 30, 2016. Our net debt is comprised of over 75% U.S. dollar borrowings and with the recent strengthening of the Canadian dollar relative to the U.S. dollar, we benefit as our net debt expressed in Canadian dollars is reduced. We also benefit from more than half of our operations being based in the U.S. along with approximately 70% of our 2017 exploration and development capital program being invested in the U.S., which mitigates our exposure to fluctuations in the Canada-U.S. dollar exchange rate.

Operating Netback

In Q2/2017, the price for West Texas Intermediate light oil ("WTI") averaged US$48.29/bbl, as compared to US$51.91/bbl in Q1/2017. Offsetting a portion of the decline in WTI was an improved pricing environment for Canadian heavy oil. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, averaged US$11.13/bbl, as compared to US$14.57/bbl in Q1/2017.

We generated an operating netback in Q2/2017 of $18.30/boe ($18.70/boe including financial derivatives gain), as compared to $19.42/boe ($19.46/boe including financial derivatives gain) in Q1/2017 and $14.39/boe ($18.13/boe including financial derivatives gain) in Q2/2016. The Eagle Ford generated an operating netback of $24.14/boe during Q2/2017 while our Canadian operations generated an operating netback of $11.71/boe.

The following table summarizes our operating netbacks for the periods noted.


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 $2.6 million in Q2/2017.

For the second half of 2017, we have entered into hedges on approximately 48% of our net WTI exposure with 9% fixed at US$54.46/bbl and 39% hedged utilizing a 3-way option structure that provides us with downside price protection at US$47.17/bbl and upside participation to US$58.60/bbl. We have also entered into hedges on approximately 49% of our net WCS differential exposure at a price differential to WTI of US$13.73/bbl and 68% of our net natural gas exposure through a combination of AECO swaps at C$3.00/mcf and NYMEX swaps at US$2.98/mmbtu.

We are also executing our hedge program for 2018. We have now entered into hedges on approximately 20% of our net WTI exposure with 15% fixed at US$51.28/bbl and 5% hedged utilizing a 3-way option structure that provides us with downside price protection at US$54.40/bbl and upside participation to US$60.00/bbl. We have also entered into hedges on approximately 20% of our net WCS differential exposure at a price differential to WTI of US$14.42/bbl and 19% of our net natural gas exposure through a combination of AECO swaps at C$2.82/mcf and NYMEX swaps at US$3.00/mmbtu.

A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2017 financial statements.

2017 Guidance

The following table summarizes our 2017 annual guidance and compares it to our 2017 year-to-date actual results.

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Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2017 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.comand EDGAR at www.sec.gov/edgar.shtml.

 


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Capital & Finance
        Operating Costs (LOE)
        Net Debt
        Debt
        Debt Maturity Schedule
        Rates of Return/ IRR
        F&D Costs / RRC
        Capital Expenditures
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        Hedging
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        Portfolio Map
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Portfolio & Operations
        IP Rates 30-Day
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        Production Mix / Split
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        Reserves
        IP Rates
Well Information
        Well Cost
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        Frac Design - Frac Stages


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