CALGARY, Alberta, Aug. 22, 2018 (GLOBE NEWSWIRE) — Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) is pleased to announce the closing of the strategic combination with Raging River Exploration Inc. (“Raging River”)(TSX: RRX).
Baytex has emerged through this transaction as a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile provided by its world class assets focused across North America. Current production is approximately 94,000 boe/d (83% liquids) from a diversified asset portfolio, including Viking, Peace River, Lloydminster and East Duvernay properties in Canada and the Eagle Ford in Texas. Baytex has a deep inventory of drilling prospects that generate top tier returns on invested capital with the capability to deliver meaningful organic production growth.
Neil Roszell, Chairman of the Board, commented “Today we have united two strong oil companies with exceptional people and assets. Our new board of directors and leadership team have laid out a detailed integration plan as we come together to create a diversified, well-capitalized oil producer with an impressive suite of high quality assets. Combined we have a platform for value creation and operational excellence and are ideally positioned to grow production and cash flow.”
Ed LaFehr, President and Chief Executive Officer, said “I am thrilled that we have repositioned Baytex to deliver industry leading returns, attractive production growth and free cash flow, with a strengthened balance sheet. Our vision is to create a self-funded North American oil producer focused on per share value creation with a target of 10 to 15 percent total annual returns. We look forward to rapidly integrating our talented teams and growing our 2018 production exit rate with strong new well performance in our core areas.”
Company Highlights (2019 Annual Estimates)
- Average annual production of 100,000 to 105,000 boe/d (85% oil and NGLs)
- Debt adjusted production per share growth of approximately 12%
- Exploration and development capital program of $750 to $850 million
- Adjusted funds flow of approximately $900 million
- Net debt to adjusted funds flow ratio of 2.2x
- Operating netback of approximately $28/boe
Notes:
- Forward strip pricing assumptions as at August 20, 2018: WTI – US$63/bbl; LLS – US$67/bbl; WCS differential – US$23/bbl; MSW differential – US$8/bbl; NYMEX Gas – US$2.80/mcf; and Exchange Rate (CAD/USD) – 1.30.
- Net debt to adjusted funds flow ratio based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow.
- Certain terms referenced above are non-GAAP measures. See advisory regarding Non-GAAP Financial and Capital Management Measures at the end of the press release.
With the closing of the transaction, we have established a new $300 million term loan facility that is due June 2020 and is secured by the assets of Raging River. This additional facility, combined with our existing facilities of US$575 million, increases our credit capacity to approximately $1.05 billion with approximately $500 million undrawn.
Operations Update
Our assets are characterized by high margins and strong capital efficiencies, resulting in industry-leading returns. With a diversified asset base and product pricing mix, we have the capability to optimize capital allocation and activity based on commodity prices and economic returns by area. In addition, we have a well-defined, low-risk drilling inventory that represents over 10 years of development opportunities in each core play.
Eagle Ford and Viking Light Oil
Our Eagle Ford and Viking light oil assets generate combined production of approximately 60,000 boe/d, representing 64% of total company volumes. These two assets are expected to generate significant cash flow in excess of their exploration and development capital.
In the Eagle Ford, we continue to see strong well performance driven by enhanced completions. During the second quarter, we commenced production from 32 gross wells and established 30-day initial production rates of approximately 1,850 boe/d per well (65% light oil and condensate) which represents an approximate 25% improvement over wells brought on production in 2017. In the Viking, 51.5 net wells were drilled during the second quarter. We currently have four drilling rigs and one frac crew executing our development program.
Heavy Oil
Our heavy oil production at Peace River and Lloydminster totals approximately 27,000 boe/d, representing 29% of total company volumes. In the northern Seal area of Peace River, our first three wells have established 30-day initial production rates of approximately 800 boe/d per well. In Lloydminster, we have recommenced our Soda Lake multi-lateral drilling program. In addition, we continue to advance our Kerrobert thermal project with first oil from the new wells anticipated in October. We currently have four heavy oil rigs running, two each in Peace River and Lloydminster.
East Duvernay Shale Light Oil
We continue to prudently advance the evaluation of the emerging Duvernay light oil play in central Alberta. As previously disclosed, the Ferrybank (02-20) and Gilby (01-20) wells are both in early stages of flow back. Two follow up delineation wells in the Pembina area have been drilled, with completions operations commencing in the next two weeks. Given the encouraging performance of the 14-36 Pembina location, we anticipate spudding the first of two development wells from the 14-36 surface pad before the end of August. Additional follow up locations are currently being licensed in both the Pembina and Ferrybank areas to allow for potential expanded activities later in the fourth quarter.
Risk Management
As part of our normal operations, we are exposed to movements in commodity prices. In an effort to manage these exposures, we utilize various financial derivative contracts, crude-by-rail and capital allocation optimization to reduce the volatility in our adjusted funds flow. We also have strong oil price diversification with 30% of liquids production commanding WTI-based pricing and 26% of liquids production (light oil and condensate in the Eagle Ford) commanding premium Louisiana Light Sweet (“LLS”) based pricing. Approximately 34% of liquids production is based on the WCS heavy oil benchmark with the balance being NGLs that are priced relative to WTI.
For Q4/2018, we have entered into hedges on approximately 37% of our net crude oil exposure. This includes 30% of our net WTI exposure with 27% fixed at US$52.27/bbl and 3% 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. In addition, we have entered into a Brent-based hedge for 4,000 bbl/d at US$61.31/bbl. We have also entered into hedges on approximately 27% of our net WCS differential exposure at a price differential to WTI of US$14.18/bbl and 29% of our net natural gas exposure through a combination of AECO swaps at C$2.82/mcf and NYMEX swaps at US$3.01/mmbtu.
For 2019, we have entered into hedges on approximately 19% of our net crude oil exposure. This includes 8% of our net WTI exposure with 5% fixed at US$61.99/bbl and 3% hedged utilizing a 3-way option structure that provides us with downside price protection at US$60.00/bbl and upside participation to US$70.00/bbl. In addition, we have entered into a Brent-based 3-way option structure for 3,000 bbl/d that provides us with downside price protection at US$69.50/bbl and upside participation to US$78.68/bbl.
With respect to heavy oil, we transport crude oil to market 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 crude by rail commitments, which to date total 7,500 bbl/d for 2019 and 5,000 bbl/d for 2020.
Growth Plans and Guidance Update
We are forecasting a Q4/2018 production rate of approximately 97,000 to 99,000 boe/d, based on exploration and development expenditures of $275 to $325 million in the second half of 2018. The following table summarizes our updated 2018 annual guidance.
Summary of 2018 Guidance
Original Guidance (1) | Updated Guidance (2) | Q4 2018 | |
Exploration and development capital ($ millions) | 325 – 375 | 450 – 500 | |
Production (boe/d) | 68,000 – 72,000 | 79,000 – 81,000 | 97,000 – 99,000 |
Expenses: | |||
Royalty rate (%) | ~ 23.0 | ~ 21.0 | |
Operating ($/boe) | 10.50 – 11.25 | 10.75 – 11.25 | |
Transportation ($/boe) | 1.35 – 1.45 | 1.35 – 1.45 | |
General and administrative ($ millions) | ~ 44 (1.72/boe) | ~ 48 (1.64/boe) | |
Interest ($ millions) | ~ 100 (3.95/boe) | ~ 105 (3.60/boe) |
Note:
- As announced on December 7, 2017.
- Includes Raging River from the closing date of the transaction (August 22, 2018).
Our preliminary 2019 plans are unchanged. With a diversified asset base and product pricing mix, we have the capability to optimize capital allocation and activity based on commodity prices and economic returns by area.
For 2019, total exploration and development expenditures are expected to be $750 to $850 million, which is designed to generate average annual production of 100,000 to 105,000 boe/d. At the mid-point, this represents debt adjusted production per share growth of approximately 12% over 2018 pro forma average annual production.
Preliminary development plans for 2019 include a heavy oil program in Canada with two drilling rigs running in each of Peace River (32 net wells) and Lloydminster (100 net wells), along with a consistent activity set in the Viking (275 net wells) and the Eagle Ford (30 net wells) which are expected to generate significant free cash flow. In addition, we will continue to delineate the East Duvernay Shale oil play with an increased pace of activity (12-20 net wells).
Summary of Preliminary 2019 Plans
Exploration and Development Capital | $750 – $850 million | |
Production | 100,000 – 105,000 boe/d | |
Oil and NGLs | ~ 85% | |
Operating Netback (1) | $28/boe | |
Adjusted Funds Flow (1) | $900 million | |
Adjusted Funds Flow per Share (2) | $ | 1.60 |
Net Debt to Adjusted Funds Flow (3) | 2.2x |
Notes:
- Pricing assumptions: WTI – US$63/bbl; LLS – US$67/bbl; WCS differential – US$23/bbl; MSW differential – US$8/bbl, NYMEX Gas – US$2.80/mcf; and Exchange Rate (CAD/USD) – 1.30.
- Based on 555 million common shares outstanding.
- Net debt ratio based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow.
- Certain terms referenced above are non-GAAP measures. See advisory regarding Non-GAAP Financial and Capital Management Measures at the end of the press release.
We expect to generate adjusted funds flow in 2019 of approximately $900 million and free cash flow (net of $575 million sustaining capital) of approximately $325 million. Each US$5/bbl increase in WTI above US$63/bbl provides an additional $130 million of adjusted funds flow on an unhedged basis. Given the significant free cash flow, we will be well-positioned to pursue organic growth, reduce debt, pursue strategic acquisitions in core areas, and consider the reinstatement of a dividend and/or share buybacks.
We will provide 2019 guidance in late 2018 upon approval by the board of directors.