UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported): March 6, 2006

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Texas (State or other jurisdiction of incorporation)		000-29187-87 (Commission File Number)		76-0415919 (I.R.S. Employer Identification No.)

1000 Louisiana Street Suite 1500 Houston, Texas (Address of principal executive offices)		77002 (Zip code)

Registrant’s telephone number, including area code: (713) 328-1000

Not applicable
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o     Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o      Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o      Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o      Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

	•		Equity in loss of Pinnacle for the quarters ended March 31, June 30 and September 30, 2005 of $1.3 million, $0.2 million and $1.9 million, respectively; and
	•		Net income (loss) for the quarters ended March 31, June 30 and September 30, 2005 of $1.6 million, $3.7 million and $(0.9) million, respectively.

     Although the Pinnacle hedges resulted in marked-to-market losses in the first and third quarters of 2005, Pinnacle has informed Carrizo that, as of March 8, 2006, the effect of accounting for the Pinnacle hedges on a marked-to-market basis would result in a gain in the first quarter of 2006 to Pinnacle of approximately $2.7 million, or a $0.9 million non-cash after-tax benefit to Carrizo’s equity investment in Pinnacle. The final amount of gain or loss for the first quarter of 2006, however, is likely to change and that change may be material. The final amount will not be determinable until after March 31, 2006 and will depend on commodity prices on such date. Pinnacle’s management is considering alternatives and procedures to qualify for cash flow hedge accounting on future derivatives.

     Although Carrizo currently owns approximately 16% of Pinnacle’s equity on a fully diluted basis, Carrizo owned 32.3% of the outstanding common stock of Pinnacle at December 31, 2005. As a result, Carrizo reports 32.3% of the changes in Pinnacle’s earnings as a line item on its income statement.

     Carrizo plans to complete its evaluation of these matters prior to the filing of its annual report on Form 10-K for the year ended December 31, 2005 (the “2005 Form 10-K”). Investors are cautioned not to rely on Carrizo’s historical financial statements for each of the quarterly periods in 2005 until such filing has been made. Particularly in light of the restatement, Carrizo expects to file with the Securities and Exchange Commission (the “SEC”) a Form 12b-25, stating that it will require additional time to complete and file the 2005 Form 10-K. Carrizo expects to release its earnings on or around March 20, 2006.

     Carrizo’s audit committee and management have discussed the matters described herein with Carrizo’s independent registered public accounting firm.

Item 8.01 Other Events.

     Carrizo is hereby filing the following discussion of its Camp Hill Project.

     Camp Hill Project. We own interests in approximately 800 gross acres in the Camp Hill field in Anderson County, Texas. We currently operate all of these leases. During the year ended December 31, 2005, the project produced an average of 46.7 Bbls/d of 19 API gravity oil. The wells produce from a depth of 500 feet and have utilized and plan to utilize a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 2005 averaged

$27.45 per barrel ($4.57 per Mcfe). The oil produced, although viscous, commands a comparable price to West Texas Intermediate crude (an average premium of $0.15 per Bbl to Koch WTI during the year ended December 31, 2005) due to its suitability as a lube oil feedstock.

     As of December 31, 2005, we had 7.1 MMBbls of proved oil reserves in this project, with 740 MBbls of oil reserves currently developed. The proved undeveloped reserves at the Camp Hill Field constitute 28.6% of our proved reserves and account for 26.0% of our present value of net future revenues from proved reserves as of December 31, 2005. We have an average working interest of approximately 92.1% in this field and an approximate net revenue interest of 71.0%.

     Prior to 2003, we estimated an ultimate recovery efficiency (i.e. the percentage of the oil in the ground that we would be able to produce economically) after steam drive of 45% of the original oil in place in the Camp Hill field. As of January 1, 2003, we raised our estimate to an ultimate recovery of 55% of the estimated original oil in place based upon our review of recovery efficiencies from prior projects by other companies in both the Camp Hill Field as well as in nearby projects that we considered to have similar geologic and hydrocarbon attributes. We have lowered our estimated recovery efficiency as of December 31, 2005 to 49% of the estimated original oil in place in the field. We believe this revised recovery efficiency is reasonable, particularly in light of the fact that a project that we have operated in the Camp Hill Field since 1993 has a current 48.7% recovery efficiency as of December 31, 2005 and is currently producing at a rate of approximately 0.8% of original oil in place per year, even without steam injection. Our estimated proved reserves for the Camp Hill Field as of year-end 2005 were adversely impacted by this revision in the recovery efficiency estimate; resulting in a reduction of 991,515 net Bbls oil as of December 31, 2005. We made other negative revisions to our December 31, 2005 Camp Hill reserves totaling 483,418 net Bbls of oil as a result of new well data and additional analysis.

     Although in 2005 we accelerated our development activities in the Camp Hill Field, this follows an extended period during which we deferred development in the field. We deferred development (1) to optimize returns by awaiting an economic entry point for developing a cogeneration plant as further explained below, (2) to pursue other opportunities in both our Gulf Coast and later, Barnett Shale areas with higher rates of return and (3) to continue increasing our net acreage position in the field in a competitive environment. Although we at all times believed that we could develop this field on a profitable basis, we nonetheless believed that we were optimizing our economic position by deferring development. We acquired our initial interests in the Camp Hill field in 1993. We performed remedial work on the existing wells and steam generators and began injecting steam in March 1994. From 1994 through 1998 and during the nine months of 2000, we injected steam in 31 patterns. In the fourth quarter of 2000, we suspended steam injection in response to high fuel gas prices and to pursue a lower steam cost solution through our cogeneration negotiations. Thereafter, we drilled one well in 2001 and seven wells in 2005.

     The most important reason for our delay in both resuming steam injection and moving to full development was the potential for significantly improved profitability that would result from the construction of a nearby cogeneration plant. Cogeneration plants typically provided steam at less than half the cost of small steam generators. Steam costs are critical to the economics of the development of the field. Expected steam costs far outweigh the capital costs for the development of the Camp Hill Field. We currently estimate approximately $139 million in steam costs compared to $22 million for drilling and development capital that is needed to fully develop the proved undeveloped reserves in this field. Previously, our management believed that the demand for electricity in the East Texas area would increase in the future such that it would become lucrative for us or a third party to build a cogeneration plant in the area. In this cogeneration plant, a gas turbine would be used to generate electricity, and the waste heat would be used to produce steam. The steam would be captured for injection in the Camp Hill field, while the electricity would be sold into the Texas electric power grid. In 2000, we engaged in discussions with another party regarding the building of a cogeneration facility, but we ultimately did not reach acceptable terms with that party. We subsequently continued to explore the possibility of a cogeneration facility in the Camp Hill field and worked with electricity industry consultants in 2002 and 2005.

     During the time we were continuing to assess the relative attractiveness of building a cogeneration plant, and in light of relatively high fuel gas costs at that time, we pursued other exploration projects primarily along the onshore Gulf Coast and in the Barnett Shale, starting in 2003, that we believed offered us potentially higher rates of return. These other projects have been the primary focus of our operations over the last several years. Our timing of Camp Hill development has also been impacted by our leasing activities in the field by which we increased our working interest and net revenue interest in our leases in the field so that we would own a greater share of these properties when we later developed them. We believe that we were able to increase our interests on more favorable terms by deferring the full scale development of the field. The addition of working interests in the Camp Hill leases further improved the economics of the development of this field as well as favorably affected the development plan for the steam drive patterns in the field.

     In 2005, we continued to invest the majority of our budgeted capital expenditures in our Barnett Shale and onshore Gulf Coast areas where the rates of return are traditionally higher and our leases expire sooner, which gives these projects greater immediacy. We did, however, drill seven gross wells (7.0 net) on four leases in the Camp Hill field in 2005, all of which are apparent successes and currently producing.

     In mid-2005, we reengaged an electricity industry consultant with cogeneration experience to further investigate the feasibility of establishing a cogeneration plant in the area. After extensive discussions with the consultant, we concluded that there continues to be overcapacity of electricity in the regional market and that overcapacity is not likely to reverse itself in the near term and that the capital expenditures associated with building a cogeneration plant are not likely to be warranted for a period of several years. As a result, we determined that,

rather than awaiting the construction of a cogeneration plant, we would instead further develop our Camp Hill properties with the existing steam generators.

     In August 2005, management proposed the acceleration of the Camp Hill development to our board of directors. Accordingly, a development plan was formally approved by the board for increased drilling activity in the Camp Hill field, beginning with an initial 60-well drilling program. In February 2006, our board of directors formally approved a multi-year plan to fully develop the entire Camp Hill field. In furtherance of this plan, we expect to drill between 35 and 40 gross wells (35 to 40 net) in this area at an estimated cost of $3.2 million during 2006. To fully develop the field, we expect to drill approximately 326 wells from 2006 through 2017, at a total cost of approximately $22 million and total operating costs including steam of approximately $175.0 million. The precise timing and amount of our expenditures on additional well drilling and increased steam injection to develop the proved undeveloped reserves in this project will depend on several factors including the relative prices of oil and natural gas.

     We have recently taken other steps to accelerate Camp Hill development. To implement our development plan, we have entered into a new fuel gas supply contact; we are upgrading the steam generator burners and burner controls; and we have obtained a 30-well drilling rig contract. This rig is expected to be in place in the field by March 17, 2006. We plan to recommence steam injection in the Camp Hill field in March 2006.

     Statements in this report, including but not limited to those relating to Carrizo’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including the timing of the completion of the restatement, current and first quarter 2006 effect of Pinnacle hedges, any restated amounts, impact of the restatement, timing of filings with the SEC, timing of release of earnings, future Camp Hill development and drilling, future reserves, the potential effects or timing of cash flow and reserve growth, shareholder value, the expected timing of drilling of additional wells and use of steam injection, plans for the drilling program and other statements that are not historical facts are forward looking statements that are based on current expectations. Although Carrizo believes that its expectations are based on reasonable assumptions, it can give no assurance that these expectations will prove correct. Important factors that could cause actual results to differ materially from those in the forward looking statements include delays and uncertainties that may be encountered in connection with the restatement, final audits and reviews by Pinnacle, Carrizo and their respective auditors, the results of Camp Hill development, the effectiveness, efficiency and cost of steam injection, the effect of Carrizo’s other exploration activities, the results and dependence on exploratory drilling activities, operating risks, oil and gas price levels, land issues, availability of equipment, weather and other risks described in Carrizo’s Form 10-K for the year ended December 31, 2004 and its other filings with the SEC. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Investors should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and Carrizo undertakes no duty to update any forward looking statement.

Item 9.01. Financial Statements and Exhibits.

     (d) Exhibits.

Exhibit Number		Description
99.1		Press Release dated March 9, 2006 Announcing Operational Results for the Fourth Quarter 2005.

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: March 9, 2006

EXHIBIT INDEX

99.1           Press Release dated March 9, 2006 Announcing Operational Results for the Fourth Quarter 2005.