Carrizo O&G Ramps Up Production to 9.3 Bcfe



Carrizo O&G reported the Company's financial results for the second quarter of 2010, which included the following highlights:

Results for the Second Quarter 2010 --

  • Record production of 9.3 Bcfe, or 102,145 Mcfe/d
  • Revenue of $32.9 million or Adjusted Revenue of $43.5 million, including the impact of realized hedges
  • Net Income of $1.8 million, or Adjusted Net Income of $11.7 million before the net non-cash items noted below
  • EBITDA, as defined below, of $31.6 million

Production volumes during the three months ended June 30, 2010 were a record 9.3 Bcfe, an increase of 1.4 Bcfe, or 18%, from second quarter 2009 production of 7.9 Bcfe and an increase of 1.0 Bcfe, or 12%, from the first quarter 2010 production of 8.3 Bcfe. The increases in production were primarily due to new Barnett Shale wells partially offset by normal production decline. Adjusted revenues from the sale of oil and gas production were $43.5 million for the second quarter of 2010, which includes oil and gas revenues of $32.9 million and realized hedge gains of $10.6 million, compared to $53.1 million for the second quarter of 2009, which includes oil and gas revenues of $25.9 million and realized hedge gains of $27.2 million. The decrease in adjusted revenues was primarily driven by lower realized gas prices partially offset by increased production. The Company's average natural gas sales price decreased 33% to $4.47 per Mcf for the second quarter of 2010 compared to $6.64 per Mcf for the second quarter of 2009 and the average oil sales price increased 33% to $75.71 per barrel for the second quarter of 2010 compared to $56.95 per barrel for the second quarter of 2009. The above prices include the impact of realized hedges. Results excluding the impact of realized hedges are presented in the table below.

For the quarter ended June 30, 2010, the Company reported adjusted net income of $11.7 million, or $0.34 per basic and diluted share, excluding an aggregate net $9.9 million non-cash, after-tax charge, comprised of (1) an unrealized loss of $4.8 million on derivatives, (2) stock-based compensation expense of $2.0 million, (3) an impairment of oil and gas properties of $1.8 million, (4) non-cash interest expense of $1.2 million associated with the amortization of the equity premium on the Company's convertible notes and deferred financing costs, and (5) bad debt expense of $0.1 million. For the quarter ended June 30, 2009, the Company reported adjusted net income of $15.8 million, or $0.51 per basic and diluted share, excluding an aggregate net $21.8 million non-cash, after-tax charge, comprised of (1) an unrealized loss of $19.2 million on derivatives, (2) stock-based compensation expense of $1.5 million and (3) non-cash interest expense of $1.1 million associated with the amortization of the equity premium on the Company's convertible notes and deferred financing costs. The Company reported net income of $1.8 million, or $0.05 per basic and diluted share, for the quarter ended June 30, 2010, as compared to net loss of $6.0 million, or $0.19 per basic and diluted share, for the same quarter during 2009.

Earnings before interest, income tax, depreciation, depletion and amortization expenses, impairment of oil and natural gas properties and certain other items described in the table below ("EBITDA") was $31.6 million, or $0.95 and $0.94 per basic and diluted share, respectively, during the second quarter of 2010 as compared to $39.5 million, or $1.27 and $1.26 per basic and diluted share, respectively, during the second quarter of 2009.

Lease operating expenses (excluding production taxes, ad valorem taxes and transportation costs) were $4.7 million (or $0.51 per Mcfe) during the three months ended June 30, 2010 as compared to $4.8 million (or $0.61 per Mcfe) for the second quarter of 2009. Lease operating expenses remained essentially unchanged as a decrease in service costs was largely offset by increased operating expenses associated with higher production. The decline in service costs was primarily driven by a decrease in operating expenses related to the pipeline and gathering system that was sold during the fourth quarter of 2009 and the increase in production from our Tarrant County Barnett Shale area, which has comparatively less associated salt water production that must be disposed of than production from other areas.

Transportation costs were $1.5 million (or $0.16 per Mcfe) during the second quarter of 2010 as compared to $3.0 million (or $0.38 per Mcfe) during the second quarter of 2009. The decrease in transportation costs per Mcfe was largely due to a change in contractual pricing effective July 1, 2009 whereby natural gas production is now sold at the wellhead.

Production taxes were $0.9 million during the second quarter of 2010 as compared to $0.3 million during the second quarter of 2009. The increase is largely attributable to a severance tax refund of $0.2 million in the second quarter of 2009 and increased production and gas prices in 2010 as compared to 2009.

Ad valorem taxes decreased to $0.5 million during the second quarter of 2010 from $1.5 million for the same quarter in 2009 primarily due to lower estimated property valuations in 2010 as compared to 2009 and a true up of the first quarter 2010 estimate of ad valorem taxes.

Depreciation, depletion and amortization ("DD&A") expenses were $11.1 million during the second quarter of 2010 (or $1.19 per Mcfe) as compared to $12.2 million (or $1.55 per Mcfe) during the second quarter of 2009. The decrease in DD&A expenses was due primarily to a lower depletion rate resulting from an impairment charge that reduced the depletable full-cost pool in the fourth quarter of 2009 and lower overall finding costs of new reserves added primarily in the fourth quarter of 2009, partially offset by increased production.

In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full-cost ceiling test impairment of $2.7 million ($1.8 million after-tax) for the quarter ended June 30, 2010 with respect to our U.K. cost center.

General and administrative ("G&A") expenses were $4.3 million during the three months ended June 30, 2010 as compared to $4.0 million during the three months ended June 30, 2009. The increase was primarily attributable to higher legal, professional and audit fees partially offset by lower compensation expense as the 2008 annual bonus to executives was approved during the second quarter of 2009 and the 2009 annual bonus to executives was approved during the third quarter of 2010.

Non-cash, stock-based compensation expense increased to $3.2 million for the three months ended June 30, 2010 from $2.3 million for the same period in 2009. The increase was primarily due to 2009 annual bonuses to non-executive employees which were approved during the second quarter of 2010 while the 2008 annual bonuses to non-executive employees were approved during the first quarter of 2009.

A $3.1 million net gain on derivatives was recorded for the second quarter of 2010 compared to a net loss of $2.3 million for the second quarter of 2009. The second quarter 2010 gain consisted of (1) an unrealized loss on derivatives of $7.5 million and (2) a realized gain on derivatives of $10.6 million. The second quarter 2009 loss consisted of (1) an unrealized loss on derivatives of $29.5 million and (2) a realized gain on derivatives of $27.2 million.

Cash interest expense, net of amounts capitalized, remained essentially unchanged at $2.9 million for the second quarter of 2010 compared to $2.8 million for the second quarter of 2009.

Non-cash interest expense, net of amounts capitalized, increased to $1.9 million for the second quarter of 2010 from $1.7 million for the second quarter of 2009, primarily due to higher amortization of deferred financing costs during the second quarter of 2010.

Results for the Six Months Ended June 30, 2010 --

  • Record production of 17.6 Bcfe, or 97,028 Mcfe/d
  • Revenue of $71.9 million or Adjusted Revenue of $87.3 million, including the impact of realized hedges
  • Net Income of $21.5 million, or Adjusted Net Income of $23.0 million before the net non-cash items noted below
  • EBITDA, as defined below, of $63.9 million

Production volumes during the six months ended June 30, 2010 were a record 17.6 Bcfe, an increase of 1.4 Bcfe, or 9%, compared to production of 16.2 Bcfe during the same period in 2009. The increase in production was primarily due to new Barnett Shale wells partially offset by normal production decline. Adjusted revenues from the sale of oil and gas production were $87.3 million for the six months ended June 30, 2010, which includes oil and gas revenues of $71.9 million and realized hedge gains of $15.4 million, compared to $102.5 million for the same period of 2009, which includes oil and gas revenues of $56.5 million and realized hedge gains of $46.0 million. The decrease in adjusted revenues was primarily driven by lower realized oil and gas prices partially offset by increased production. The Company's average natural gas sales price decreased 22% to $4.77 per Mcf for the first six months of 2010 compared to $6.12 per Mcf for the first six months of 2009 and the average oil sales price decreased six percent to $75.92 per barrel for the first six months of 2010, compared to $80.52 per barrel for the first six months of 2009. The above prices include the impact of realized hedges. Results excluding the impact of realized hedges are presented in the table below.

For the six months ended June 30, 2010, the Company reported adjusted net income of $23.0 million, or $0.71 and $0.70 per basic and diluted share, respectively, excluding an aggregate net $1.5 million non-cash, after-tax charge, comprised of (1) an unrealized gain of $6.5 million on derivatives, (2) stock-based compensation expense of $3.4 million, (3) non-cash interest expense of $2.6 million associated with the amortization of the equity premium on the Company's convertible notes and deferred financing costs, (4) an impairment of oil and gas properties of $1.8 million, and (5) bad debt expense of $0.2 million. For the six months ended June 30, 2009, the Company reported adjusted net income of $28.4 million, or $0.92 and $0.91 per basic and diluted share, respectively, excluding an aggregate net $159.9 million non-cash, after-tax charge, comprised of (1) an impairment of oil and gas properties of $140.6 million, (2) an unrealized loss of $11.9 million on derivatives, (3) stock-based compensation expense of $3.7 million, (4) an impairment of investment of $1.3 million, (5) non-cash interest expense of $2.2 million associated with the amortization of the equity premium on the Company's convertible notes and deferred financing costs, and (6) bad debt expense of $0.2 million. The Company reported net income of $21.5 million, or $0.66 and $0.65 per basic and diluted share, respectively, for the six months ended June 30, 2010, as compared to net loss of $131.6 million, or $4.25 per basic and diluted share, for the same period during 2009.

EBITDA was $63.9 million, or $1.96 and $1.94 per basic and diluted share, respectively, during the six months ended June 30, 2010 as compared to $76.7 million, or $2.48 and $2.45 per basic and diluted share, respectively, during the six months ended June 30, 2009.

Lease operating expenses (excluding production taxes, ad valorem taxes and transportation costs) were $8.5 million (or $0.48 per Mcfe) during the six months ended June 30, 2010 as compared to $10.0 million (or $0.62 per Mcfe) for the six months ended June 30, 2009. The decrease in lease operating expenses was due to a decrease in service costs partially offset by increased operating expenses associated with higher production. The decline in service costs was driven primarily by a decrease in operating expenses related to the pipeline and gathering system that was sold during the fourth quarter of 2009 and the increase in production from our Tarrant County Barnett Shale area, which has comparatively less associated salt water production that must be disposed of than production from other areas.

Transportation costs were $2.8 million (or $0.16 per Mcfe) for the six months ended June 30, 2010 as compared to $6.3 million (or $0.39 per Mcfe) during the same period of 2009. The decrease was primarily a result of a change in contractual pricing effective July 1, 2009 whereby natural gas production is now sold at the wellhead.

Production taxes increased from a credit of $(1.0) million in the first six months of 2009 to $1.8 million for the same period in 2010 as a result of a severance tax refund of $2.0 million in 2009 and increased production and gas prices in 2010 as compared to 2009.

Ad valorem taxes decreased to $1.7 million for the six months ended June 30, 2010 from $2.4 million for the same period in 2009 primarily due to lower estimated property valuations in 2010 as compared to 2009.

DD&A expenses for the six months ended June 30, 2010 decreased to $20.9 million (or $1.19 per Mcfe) from $27.5 million (or $1.70 per Mcfe) for the same period in 2009. This decrease in DD&A was primarily due to a lower depletion rate resulting from impairment charges that reduced the depletable full-cost pool in the first and fourth quarters of 2009 and lower overall finding costs of new reserves added primarily in the fourth quarter of 2009, partially offset by increased production.

In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full cost ceiling test impairment of $2.7 million ($1.8 million after-tax) for the six months ended June 30, 2010 with respect to our U.K. cost center.

G&A expenses were $8.7 million during the six months ended June 30, 2010 as compared to $8.2 million during the six months ended June 30, 2009. The increase was due primarily to higher legal, professional and audit fees that were partially offset by lower compensation expenses as the 2008 annual bonuses to executives were approved during the second quarter of 2009 and the 2009 annual bonuses to executives were approved during the third quarter of 2010.

Non-cash, stock-based compensation expense was $5.3 million for the six months ended June 30, 2010 compared to $5.7 million for the same period in 2009. The decrease was primarily due to a higher level of amortization in 2009 associated with higher priced restricted stock awards granted in prior years.

A $25.7 million net gain on derivatives was recorded for the first six months of 2010 compared to a net gain of $27.8 million for the first six months of 2009. The 2010 gain consisted of (1) the unrealized gain on derivatives of $10.3 million and (2) the realized gain on derivatives of $15.4 million. The 2009 gain consisted of (1) the unrealized loss on derivatives of $18.2 million and (2) the realized gain on derivatives of $46.0 million.

Cash interest expense, net of amounts capitalized, was $6.1 million for the first six months of 2010 compared to $5.3 million for the first six months of 2009. The increase was primarily attributable to increased interest expense associated with the higher debt levels on the revolving credit facility and lower levels of capitalized interest.

Non-cash interest expense, net of amounts capitalized, increased to $4.1 million for the first six months of 2010 from $3.3 million for the first six months of 2009, primarily due to higher amortization of deferred financing costs during 2010.

Carrizo President and CEO S. P. "Chip" Johnson, IV, commented, "Our production for the quarter came in ahead of forecast due to the faster clean-up and better initial response of new Barnett wells completed during the quarter and the optimal management of the producing wells at our facility on the University of Texas at Arlington campus during completion activities. We are now in the final stages of completing the last 8 wells on this 22 well pad. We moved one of our Helmerich & Payne rigs out of the Barnett Shale to drill our initial three horizontal Eagle Ford Shale wells in LaSalle County. We have reached total depth on our first well and are finishing up the second, both with lateral legs of over 5,000'. The information generated during the course of drilling these wells is encouraging and we expect to move the rig to the third well following completion of drilling the second well. We plan to frac and complete these wells later this year. We have had some success in adding acreage in both the Eagle Ford and Niobrara plays recently. We currently own around 17,000 acres in the Eagle Ford and 58,000 acres in the northern D. J. Basin prospective for Niobrara oil. We expect that our first Niobrara well should spud in September and we hope to drill three horizontal wells in this play by the end of the year. We have contracted an additional rig to initiate our development drilling in Pennsylvania with our new partner Reliance Industries, and are on track for a September start date.

"We believe that even modest success in any of these new areas of activity will have a significant positive impact on 2011 production and cash flow."


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