Baytex Announces First Quarter 2019 Financial and Operating Results

Source Press Release
Company Baytex Energy Corp. 
Tags Eagle Ford, Unconventional Resources, Capital Spending, Guidance, Financial & Operating Data, Strategy - Corporate
Date May 02, 2019

Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its operating and financial results for the three months ended March 31, 2019 (all amounts are in Canadian dollars unless otherwise noted).

“This marks the first quarter where we have demonstrated the benefit of the Baytex and Raging River combination as we have increased our operating netback, delivered meaningful free cash flow and started to strengthen our balance sheet. Our first quarter results were underpinned by robust operating performance across our asset base in Canada and the U.S. Our sound operating results, combined with improved pricing in Canada, resulted in a 100% increase in our adjusted funds flow compared to the fourth quarter of 2018. We are well positioned to execute our business plan focused on free cash flow generation,” commented Ed LaFehr, President and Chief Executive Officer.

2019 Outlook

Based on the forward strip for 2019(1), we are now forecasting adjusted funds flow for 2019 of approximately $950 million. Further deleveraging remains a top priority with adjusted funds flow now exceeding the midpoint of our capitalguidance by $350 million, which will support accelerated debt repayment.

Given our strong operating performance to date, we are tightening our 2019 production guidance range to 95,000 to 97,000 boe/d (previously 93,000 to 97,000 boe/d) with budgeted exploration and development capital expenditures of $575 to $625 million (previously $550 to $650 million).

(1)  Pricing assumptions: WTI - US$61/bbl; LLS - US$67/bbl; WCS differential - US$15/bbl; MSW differential – US$6/bbl, NYMEX Gas - US$2.80/mcf; AECO Gas - $1.50/mcf and Exchange Rate (CAD/USD) - 1.34.

Q1/2019 Highlights

  • Generated production of 101,115 boe/d (84% oil and NGL), exceeding the high end of our annual guidance and a 2% increase over Q4/2018.
  • Delivered adjusted funds flow of $221 million ($0.40 per basic share), a 100% increase compared to $111 million ($0.20 per basic share) in Q4/2018.
  • Reduced net debt by $90 million during the quarter as adjusted funds flow exceeded capital expenditures.
  • Realized an operating netback of $26.56/boe ($28.63/boe including financial derivatives).
  • Eagle Ford production increased 7% to 41,097 boe/d, representing the highest quarterly production rate achieved in the field and reflects continued strong well performance and an active first quarter completion program.
  • Production in Canada remained strong at 60,018 boe/d. We maintained a consistent development program in the Viking and reinitiated activity on our heavy oil assets, including the completion of three previously deferred wells at Peace River.
  • Continued to advance the evaluation of the East Duvernay Shale where two of four planned wells were drilled. Completion activities are scheduled to commence in Q2/2019 to confirm well productivities and the de-risking of the majority of our 250 sections of land in the Pembina area.
  • Extended the maturity of our revolving credit facilities to April 2021. We maintain strong financial liquidity with our credit facilities approximately 50% undrawn.
  Three Months Ended 
  March 31, 2019    December 31, 2018      March 31, 2018   
FINANCIAL 
(thousands of Canadian dollars, except per common share amounts) 
                 
Petroleum and natural gas sales  453,424    358,437    286,067   
Adjusted funds flow (1)    220,770      110,828      84,255   
Per share - basic    0.40      0.20      0.36   
Per share - diluted    0.40      0.20      0.36   
Net income (loss)    11,336      (231,238    (62,722 
Per share - basic    0.02      (0.42    (0.27 
Per share - diluted    0.02      (0.42    (0.27 
                   
Capital Expenditures                   
Exploration and development expenditures (1)  153,843    184,162    93,534   
Acquisitions, net of divestitures        183      (2,026 
Total oil and natural gas capital expenditures  153,843    184,345    91,508   
                   
Net Debt                   
Bank loan (2)  550,751    522,294    212,571   
Long-term notes (2)    1,569,153      1,596,323      1,525,595   
Long-term debt    2,119,904      2,118,617      1,738,166   
Working capital deficiency    55,337      146,550      45,213   
Net debt (1)  2,175,241    2,265,167    1,783,379   
                   
Shares Outstanding - basic (thousands)                   
Weighted average    555,438      554,036      236,315   
End of period    555,872      554,060      236,578   
   
  Three Months Ended 
  March 31, 2019    December 31, 2018    March 31, 2018   
OPERATING       
Daily Production       
Light oil and condensate (bbl/d)  45,048    44,987    20,967   
Heavy oil (bbl/d)  26,891    26,339    24,868   
NGL (bbl/d)  11,729    10,327    9,143   
Total liquids (bbl/d)  83,668    81,653    54,978   
Natural gas (mcf/d)  104,682    103,424    87,261   
Oil equivalent (boe/d @ 6:1) (3)  101,115    98,890    69,522   
       
Netback (thousands of Canadian dollars)       
Total sales, net of blending and other expense (4)  436,636    344,682    268,777   
Royalties  (81,325  (79,765  (64,839 
Operating expense  (100,292  (97,857  (65,888 
Transportation expense  (13,330  (10,994  (8,519 
Operating netback  241,689    156,066    129,531   
General and administrative  (14,136  (14,096  (11,008 
Cash financing and interest  (28,184  (27,933  (24,511 
Realized financial derivatives gain (loss)  18,814    (3,063  (9,841 
Other (5)  2,587    (146  84   
Adjusted funds flow (1)  220,770    110,828    84,255   
       
Netback (per boe)       
Total sales, net of blending and other expense (4)  47.98    37.89    42.96   
Royalties  (8.94  (8.77  (10.36 
Operating expense  (11.02  (10.76  (10.53 
Transportation expense  (1.46  (1.21  (1.36 
Operating netback (1)  26.56    17.15    20.71   
General and administrative  (1.55  (1.55  (1.76 
Cash financing and interest  (3.10  (3.07  (3.92 
Realized financial derivatives gain (loss)  2.07    (0.34  (1.57 
Other (5)  0.28    (0.02  0.01   
Adjusted funds flow (1)  24.26    12.17    13.47   

Notes:

  1. The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to the advisory on non-GAAP measures at the end of this press release.
  2. Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of liquidity or repayment obligations.
  3. 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.
  4. Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
  5. Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the Q1/2019 MD&A for further information on these amounts.

Operating Results

Our operating results for the first quarter of 2019 were buoyed by record production in the Eagle Ford and strong operating performance in Canada in a much improved commodity price environment. We successfully executed our first quarter drilling program and continued to drive cost and capital efficiency in our business. We are now realizing the benefits of the Baytex and Raging River combination as we increase our operating netback, deliver meaningful free cash flow and strengthen our balance sheet.

Production during the first quarter averaged 101,115 boe/d (84% oil and NGL), as compared to 98,890 boe/d (83% oil and NGL) in Q4/2018, exceeding the high end of our full-year production guidance range.   

Exploration and development expenditures totaled $154 million in Q1/2019, consistent with the mid-point of our guidance range of $600 million. We participated in the drilling of 126 (86.6 net) wells with a 99% success rate during the first quarter.

Eagle Ford and Viking Light Oil

Production in the Eagle Ford averaged 41,097 boe/d (78% liquids) during Q1/2019, as compared to 38,437 boe/d in Q4/2018. This represents the highest quarterly production rate ever achieved in the field and reflects continued strong well performance and an active first quarter completion program. We commenced production from 36 (8.9 net) wells during the first quarter, representing approximately one-third of our planned 2019 activity. The wells brought on-stream generated an average 30-day initial production rate of approximately 1,600 boe/d per well.

During Q1/2019, production from the Viking averaged 23,387 boe/d, as compared to 23,784 boe/d in Q4/2018. We maintained a steady pace of development in Q1/2019 with five drilling rigs and 1.5 frac crews executing our program, resulting in 79 (67.8 net) wells. We continue to experience positive results from our extended reach horizontal drillingprogram, which now represents 85% of our Viking activity. Our capital program includes the seasonal slowdown in Q2/2019 and we remain on track to drill approximately 250 net wells this year.

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 29,341 boe/d during the first quarter, as compared to 28,290 boe/d in Q4/2018. As commodity prices and operating netbacks improved during the first quarter, we reinitiated field activity, including the completion of three previously deferred wells at Peace River. In addition, we continued the ramp-up of our Kerrobert thermal expansion project achieving a peak production rate of 2,500 bbl/d. We have also expanded our acreage position at Peace River, acquiring an additional 26 sections of prospective land. We expect to drill our first exploratory multilateral well on these lands in 2019. 

With WCS differentials returning to historical levels, the returns associated with continued development of our heavy oil assets are now competitive or superior to those of our other plays, allowing potential increased capital allocation to those assets in the second half of 2019.

East Duvernay Shale Light Oil

We continue to prudently advance the delineation of the East Duvernay Shale, an early stage, high operating netback light oil resource play where we have amassed over 450 sections of land. During Q1/2019, we drilled two of four planned land retention and appraisal wells. The wells drilled to date have confirmed that the net reservoir thickness and geological characteristics remain consistent through the southern extent of our Pembina acreage. Completion activities are scheduled to commence in Q2/2019 to confirm well productivities and the de-risking of the majority of our 250 sections of land in the Pembina area.

Financial Review

Our adjusted funds flow in Q1/2019 increased 100% as compared to Q4/2018, driven by strong operating performance and the cash generating capability of our assets in an improved commodity price environment. We generated adjusted funds flow of $221 million ($0.40 per basic share) in Q1/2019, compared to $111 million ($0.20 per basic share) in Q4/2018.

In Q1/2019, the price for West Texas Intermediate light oil (“WTI”) averaged US$54.90/bbl, as compared to US$58.81/bbl in Q4/2018. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$12.29/bbl in Q1/2019 as compared to US$39.42/bbl in Q4/2018. The discount for Canadian light oil, as measured by the price differential between Canadian Mixed Sweet Blend (“MSW”) and WTI, averaged US$4.85/bbl in Q1/2019 as compared to US$26.51/bbl in Q4/2018.

We generated an operating netback of $26.56/boe in Q1/2019, as compared to $17.15/boe in Q4/2018 and $20.71/boe in Q1/2018. The Eagle Ford generated an operating netback of $28.94/boe during Q1/2019 while our Canadian operations generated an operating netback of $24.92/boe.

In the Eagle Ford, our assets are proximal to Gulf Coast markets with light oil and condensate production priced off the LLS crude oil benchmark, which is a function of the Brent price. In Q1/2019, the price for LLS averaged US$61.60/bbl as compared to US$66.64/bbl in Q4/2018. During Q1/2019, our light oil and condensate realized price in the Eagle Ford was US$57.23/bbl (or $76.06/bbl) representing a US$4.37/bbl discount to LLS.

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

 
  Three Months Ended March 31 
  2019  2018 
($ per boe except for production)  Canada    U.S.    Total    Canada    U.S.    Total   
Production (boe/d)  60,018    41,097    101,115    33,505    36,017    69,522   
             
Total sales, net of blending and other (1)  45.77    51.20    47.98    29.69    55.30    42.96   
Royalties  (4.66  (15.18  (8.94  (3.76  (16.51  (10.36 
Operating expense  (13.72  (7.08  (11.02  (15.06  (6.31  (10.53 
Transportation expense  (2.47  —    (1.46  (2.83  —    (1.36 
Operating netback (2)  24.92    28.94    26.56    8.04    32.48    20.71   
Realized financial derivatives gain (loss)  —    —    2.07    —    —    (1.57 
Operating netback after financial derivatives  24.92    28.94    28.63    8.04    32.48    19.14   

Notes:

  1. Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
  2. The term “operating netback” does not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to the advisory on non-GAAP measures at the end of this press release.

Financial Liquidity

On May 2, 2019, we extended the maturity of our revolving credit facilities to April 2021. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. Our credit facilities total approximately $1.07 billion, comprised of US$575 million of revolving credit facilities and a $300 million non-revolving term loan.

Our net debt, which includes our bank loan, long-term notes and working capital, totaled $2.2 billion at March 31, 2019, down from $2.3 billion at December 31, 2018. We maintain strong financial liquidity with our credit facilities approximately 50% undrawn and our first long-term note maturity not until 2021.

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 realized a financial derivatives gain of $19 million in Q1/2019.  

For the balance of 2019, we have now entered into hedges on approximately 45% of our net crude oil exposure, up from approximately 30% two months ago. This includes 40% of our net WTI exposure with 17% fixed at US$62.72/bbl and 23% hedged utilizing a 3-way option structure that provides us with a US$10/bbl premium to WTI when WTI is at or below US$55.64/bbl and allows upside participation to US$73.65/bbl. In addition, we have entered into a Brent-based 3-way option structure for 3,000 bbl/d that provides a US$10/bbl premium to Brent when Brent is at or below US$59.50/bbl and allows upside participation to US$78.68/bbl. We have also entered into hedges on approximately 22% of our net natural gas exposure through a series of NYMEX swaps at US$3.10/mmbtu. For 2020, we have entered into hedges on approximately 15% of our net crude oil exposure, utilizing a 3-way option structure that provides us with a US$9/bbl premium to WTI when WTI is at or below US$51.00/bbl and allows upside participation to US$66.06/bbl.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For 2019, we expect to deliver 11,000 bbl/d (approximately 40%) of our heavy oil volumes to market by rail, up from 9,000 bbl/d in 2018. Approximately 70% of our crude by rail commitments are WTI based contracts with no WCS pricing exposure. In addition, for the balance of 2019, we have entered into WCS differential hedges on approximately 13% of our net heavy oil exposure at a WTI-WCS differential of US$17.49/bbl. We have also entered into a WTI-MSW basis differential swap for 4,000 bbl/d of our light oil production in Canada at US$8/bbl for June 2019 to December 2019.

A complete listing of our financial derivative contracts can be found in Note 18 to our Q1/2019 financial statements.

Outlook for 2019

Global benchmark prices have continued to improve with WTI currently trading at US$64/bbl, as compared to an average of US$55/bbl in Q1/2019. In addition, Canadian light and heavy oil differentials remain strong. For April and May, the WTI-WCS price differential averaged US$10.62/bbl and US$8.43/bbl, respectively, and the WTI-MSW price differential averaged US$4.69/bbl and US$3.70/bbl, respectively. This combination of improved WTI prices and the narrowing of Canadian differentials is expected to have a further positive impact to our full year adjusted funds flow.

Given our strong Q1/2019 operating performance, we are tightening our 2019 production guidance range to 95,000 to 97,000 boe/d (previously 93,000 to 97,000 boe/d) with budgeted exploration and development capital expenditures of $575 to $625 million (previously $550 to $650 million). We are also updating our guidance for general and administrative expense to reflect a change associated with the adoption of IFRS 16.

Based on the forward strip for 2019(1), we are forecasting adjusted funds flow of approximately $950 million. Further deleveraging remains a top priority. For 2019, adjusted funds flow in excess of exploration and development expenditures, leasing expenditures and asset retirement obligations, will be used to reduce our indebtedness. Our year end 2019 net debt to adjusted funds flow ratio is forecast to be 2.0x.

As we continue to drive debt levels down, we will be positioned to enhance shareholder returns through a combination of organic growth, disciplined capital allocation, the reinstatement of a dividend and/or share buybacks.

The following table summarizes our updated 2019 annual guidance.

     
  Guidance  Q1/2019 
Exploration and development capital ($ millions) (2)  $575 - $625  $153.8 
Production (boe/d) (2)  95,000 - 97,000  101,115 
     
Expenses:     
Royalty rate (%)  20%  18.6% 
Operating ($/boe)  $10.75 - $11.25  $11.02 
Transportation ($/boe)  $1.25 - $1.35  $1.46 
General and administrative ($ millions)  $46 ($1.30/boe)  $14.1 ($1.55/boe) 
Interest ($ millions)  $112 ($3.23/boe)  $28.2 ($3.10/boe) 
     
Leasing expenditures ($ millions)  $5  1.4 
Asset retirement obligations ($ millions)  $17  4.9 
  1. Pricing assumptions: WTI - US$61/bbl; LLS - US$67/bbl; WCS differential - US$15/bbl; MSW differential – US$6/bbl, NYMEX Gas - US$2.80/mcf; AECO Gas - $1.50/mcf and Exchange Rate (CAD/USD) - 1.34.
  2. Our exploration and development capital and production guidance for 2019 has been updated as of May 2, 2019. Original guidance from December 2018: production – 93,000-97,000 boe/d; exploration and development capital - $550-$650 million.

The following table summarizes our annual adjusted funds flow sensitivities to changes in commodity prices and the CAD/USD exchange rate.

     
  Excluding Hedges
($ millions) 
Including Hedges 
($ millions) 
Change of US$1.00/bbl WTI crude oil  $29.1  $21.3 
Change of US$1.00/bbl WCS heavy oil differential  $11.3  $9.3 
Change of US$1.00/bbl MSW light oil differential  $10.6  $10.6 
Change of US$0.25/mcf NYMEX natural gas  $9.2  $7.3 
Change of $0.01 in the CAD/USD exchange rate  $12.2  $12.2 
Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd