Annual Reports

 
Quarterly Reports

 
8-K

 
Other

Rosehill Resources Inc. 10-K 2006
Form 10-K for the period ended December 31, 2005
Table of Contents
Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-K

 

x Annual Report Pursuant To Section 13 or 15(d) of The Securities Exchange Act of 1934 For The Fiscal Year Ended December 31, 2005

 

¨ Transition Report Pursuant To Section 13 Or 15(d) of The Securities Exchange Act of 1934

 


Commission File Number: 000-51801

 


ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

Delaware   43-2083519
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
717 Texas, Suite 2800, Houston, TX   77002
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (713) 335-4000

 


SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

None

SECURITIES LISTED PURSUANT TO SECTION 12(g) OF THE ACT:

 

Common Stock, $.001 Par Value   Nasdaq National Market
(Title of Class)   (Name of Exchange on which registered)

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act of 1933.    Yes  ¨     No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ¨     No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer as defined in Rule 12b-2 of the Securities Exchange Act of 1934.

 

¨    Large accelerated filer   ¨    Accelerated filer   x    Non-Accelerated filer

Indicate by check mark whether the registrant is a shell company as defined by Rule 12b-2 of the Securities Exchange Act of 1934.    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of April 10, 2006 was approximately $934 million based on the closing price of $18.55 per share on the Nasdaq National Market.

The number of shares of the registrant’s Common Stock, $.001 par value per share outstanding as of April 10, 2006 was 50,587,269.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III will either be included in Rosetta Resources Inc. definitive proxy statement filed with the Securities and Exchange Commission or filed as an amendment to this Form 10-K no later than 120 days after the end of the Company’s fiscal year, to the extent required by the Securities Exchange Act of 1934, as amended.

 



Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

          PAGE
PART I      
ITEM 1.    Business    1
ITEM 1A.    Risk Factors    17
ITEM 1B.    Unresolved Staff Comments    28
ITEM 2.    Properties    28
ITEM 3.    Legal Proceedings    29
ITEM 4.    Submission of Matters to a Vote of Security Holders    29
PART II      
ITEM 5.    Market for Registrant’s Common Equity and Related Stockholder Matters    31
ITEM 6.    Selected Financial Data    33
ITEM 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    36
ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk    59
ITEM 8.    Financial Statements and Supplementary Data    61
ITEM 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    111
ITEM 9A.    Controls and Procedures    111
ITEM 9B.    Other Information    112
PART III      
ITEM 10.    Directors and Executive Officers of the Registrant    113
ITEM 11.    Executive Compensation    113
ITEM 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    113
ITEM 13.    Certain Relationships and Related Transactions    113
ITEM 14.    Principal Accountant Fees and Services    113
PART IV      
ITEM 15.    Exhibits and Financial Statement Schedules    114


Table of Contents
Index to Financial Statements

Cautionary Note

This annual report contains forward-looking statements of our management regarding factors that we believe may affect our performance in the future. Such statements typically are identified by terms expressing our future expectations or projections of revenues, earnings, earnings per share, cash flow, market share, capital expenditures, effects of operating initiatives, gross profit margin, debt levels, interest costs, tax benefits and other financial items. All forward-looking statements, although made in good faith, are based on assumptions about future events and are therefore inherently uncertain, and actual results may differ materially from those expected or projected. Important factors that may cause our actual results to differ materially from expectations or projections include those described under the heading “Forward-Looking Statements” in Item 7. Forward-looking statements speak only as of the date of this report, and we undertake no obligation to update or revise such statements to reflect new circumstances or unanticipated events as they occur.

For a glossary of oil and gas terms, see page 119.

PART I

Item 1. Business.

GENERAL

Rosetta Resources Inc. (the “Company”) is comprised of the domestic oil and natural gas business formerly owned by Calpine Corporation and affiliates (predecessor, “Calpine”) acquired in July 2005 by the Company (successor). The Company is engaged in oil and natural gas exploration, development, production and acquisition activities in the United States, and operates in one business segment. Our operations are primarily concentrated in the Sacramento Basin of California, Lobo and Perdido Trends in South Texas, the State Waters of Texas, the Gulf of Mexico and the Rocky Mountains. The Company was formed in June 2005 to acquire the domestic oil and natural gas business of Calpine. This acquisition closed in July 2005.

Pursuant to the acquisition, we entered into several operative contracts with Calpine, including a purchase and sale agreement under which we have indemnification rights and obligations with respect to Calpine. Currently, Calpine provides pipeline services, including personnel, under the transition services agreement and markets our gas under a marketing agreement. We sell a significant portion of our gas to Calpine pursuant to certain gas purchase and sales contracts.

In October 1999, Calpine purchased Sheridan Energy, Inc. (“Sheridan”), a natural gas exploration and production company operating in northern California and the Gulf Coast region. The Sheridan acquisition provided the initial management team an operational infrastructure to evaluate and acquire oil and natural gas properties for Calpine. In December 1999, Calpine purchased Vintage Petroleum, Inc.’s interest in the Rio Vista Gas Unit and related areas, representing primarily natural gas reserves located in the Sacramento Basin in northern California. Sheridan was purchased by Calpine in 1999 and renamed Calpine Natural Gas Company and then was merged into Calpine in April 2002, and Rosetta Resources Operating LP (formerly known as Calpine Natural Gas L.P.; “RROLP”) was subsequently established. In October 2001, Calpine completed the acquisition of 100% of the voting stock of Michael Petroleum Corporation, a natural gas exploration and production company with operations in south Texas. In September 2004, Calpine sold its natural gas reserves in the New Mexico San Juan Basin and Colorado Piceance Basin and such properties have been reflected as discontinued operations for all periods presented herein. Several members of the Calpine management team, who were responsible for operating Calpine’s oil and natural gas business, joined the Company concurrently with the acquisition of the properties from Calpine.

 

1


Table of Contents
Index to Financial Statements

OUR STRENGTHS

We believe our historical success is, and future performance will be, directly related to the following combination of strengths:

High Quality, Diversified Asset Base. We own a geographically diversified asset base comprised of long-lived reserves along with shorter-lived, higher return reserves. Approximately 96% of our reserves are natural gas, and almost all of our assets are located in the Sacramento Basin of California, South Texas, the Gulf of Mexico and the Rocky Mountains. We believe this geographic and production profile diversity will enhance the stability of our cash flows while providing us with a large number of development and exploration opportunities, as well as support for additional acquisitions.

Development and Exploration Drilling Inventory. We have identified over 500 drillable, low to moderate risk opportunities providing us with multiple years of drilling inventory, and we expect to drill approximately one-third of these locations during 2006. Approximately 123 of these locations are classified as proved undeveloped. We also have a large and diversified portfolio of what we designate as development and exploration prospects. Our capital expenditure budget, including potential acquisitions, is approximately $199 million for 2006. We will manage our exploratory risks and expenditures by selectively reducing our capital exposure in certain high risk projects by partnering with others in our industry.

Operational Control. We operate approximately 90% of our estimated proved reserves, which allows us to more effectively manage expenses and control the timing of capital allocation of our development and exploration activities.

Experienced Management Team. Our executive management has an average of over 25 years of experience in the oil and natural gas industry.

Proven Management Team, Including Technical and Land Personnel, with Access to Technological Resources. Our technical staff includes 26 geologists, geophysicists, landmen, engineers and technicians with an average of over 20 years of relevant technical experience. Our staff has a proven record of analyzing complex structural and stratigraphic plays using 3-D geophysical expertise, producing and optimizing low pressure natural gas reservoirs, detecting low contrast, low permeability pay opportunities, drilling, completing and fracing of deep tight natural gas reservoirs, conducting Gulf of Mexico operations and managing horizontal drilling and coalbed methane operations. These core competencies helped us to achieve a drilling success rate of over 80% for the six months ended December 31, 2005 and has helped maximize recovery from our reservoirs. Our definition of drilling success is a well that produces hydrocarbons at sufficient rates, to allow us to recover, at a minimum, our capital investment and operating costs.

OUR STRATEGY

Our strategy is to increase stockholder value by profitably increasing our reserves, production, cash flow and earnings using a balanced program of (1) developing existing properties, (2) exploring undeveloped properties, (3) completing strategic acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:

Further Development to Existing Properties. We intend to further develop the significant remaining upside potential of our properties by working over existing wells, drilling infill locations, drilling step-out wells to expand known field outlines, tapping logged behind pipe pays and lowering field line pressures for additional recoveries. Many of these opportunities were not fully exploited prior to the formation of Rosetta.

Exploration Growth. We intend to focus on niche areas in which we have technological and operational advantages. This growth will come from higher-risk, higher-impact opportunities offshore in the Gulf of Mexico, along the Wilcox Trend in South Texas, in deep horizons in the Sacramento Basin, and from lower-risk, longer-lived drilling in the shallow Sacramento Basin, the Lobo Sand Trend in South Texas, the Wasatch and Mesa

 

2


Table of Contents
Index to Financial Statements

Verde formations in the Uinta Basin, Niobrara chalk in the DJ Basin and coalbed methane in the San Juan Basin. While the majority of our prospects will be internally generated, we will, from time to time, participate in third party drilling opportunities.

Acquisition Growth. We will continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We will particularly focus on opportunities where we believe our reservoir management and operational expertise will enhance the value and performance of acquired properties. Initial acquisition targets will be in and around our major producing and activity areas. We will also use our minor producing field ownerships as islands of control and knowledge to make strategic acquisitions. Our management team has demonstrated success in acquisitions in the past ten years and has developed a significant knowledge base of producing oil and natural gas fields throughout the United States.

Maintain Technological Expertise. We intend to maintain the technological expertise that helped us to achieve a drilling success rate of over 80% for the six months ended December 31, 2005 and helped us maximize field recoveries. We will use advanced geological and geophysical technologies, detailed petrophysical analyses, state-of-the-art reservoir engineering and sophisticated completion and stimulation techniques to grow our reserves and production.

Endeavor to be a Low Cost Producer. We will strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and capture operating efficiencies. This is particularly true in the Sacramento Basin because of our position as the dominant producer in the region.

Maintain Financial Flexibility. We intend to optimize unused borrowing capacity under our revolving line of credit by periodically refinancing our bank debt in the capital markets when conditions are favorable. As of December 31, 2005, we had $160 million available for borrowing under our revolving line of credit. Additionally, we expect internally generated cash flow to provide additional financial flexibility, allowing us to pursue our business strategy. We intend to actively manage our exposure to commodity price risk in the marketing of our oil and natural gas production. As part of this strategy and in connection with our credit facilities, we entered into natural gas fixed-price swaps for a significant portion of our expected production through 2009. Additionally, in the fourth quarter 2005, we entered into costless collar contracts for a portion of our 2006 production. We may enter into other agreements, including fixed price, forward price, physical purchase and sales contracts, futures, financial swaps, option contracts and put options.

CALPINE BANKRUPTCY

On December 20, 2005, Calpine and certain of its subsidiaries, including Calpine Fuels, filed for federal bankruptcy protection in the Southern District of New York. The filing raises certain concerns regarding aspects of our relationship with Calpine which we will closely monitor as the Calpine bankruptcy proceeds. Following are our principal areas of concern:

 

    The bankruptcy court may challenge the fairness of our acquisition. For a number of reasons, including the process which Calpine followed in allowing market forces to set the purchase price for the acquisition, we believe that it is unlikely that any challenge to the fairness of our acquisition would be successful.

 

    The bankruptcy proceeding may prevent, frustrate or delay our ability to receive record legal title to certain properties originally determined to be non-consent properties which we are entitled to obtain under our purchase and sale agreement with Calpine and certain subsidiaries.

 

    Additionally, the bankruptcy proceeding may prevent, frustrate or delay our ability to receive corrective documentation from Calpine for certain properties which we bought from Calpine and paid for, where the documentation delivered by Calpine was incomplete, including documentation related to certain ministerial governmental approvals.

 

3


Table of Contents
Index to Financial Statements
    Calpine may stop purchasing gas from us under our gas purchase contract with Calpine. Since the date of the bankruptcy filing, Calpine has continued buying natural gas from us and paying for it timely. The bankruptcy court for Calpine, as debtor-in-possession, has given approval to continue payments to us for our delivery of natural gas under our gas purchase and sale agreement. Under the terms of this contract, we are entitled to sell this gas to third parties at comparable prices and terms if this occurs and expect to be able to minimize our exposure to four days of sales under the contract, or approximately $1.4 million in lost sales at production rates and prices as of December 31, 2005.

 

    Calpine may stop providing us certain services, including natural gas marketing services and pipeline services, which Calpine, through separate subsidiaries, currently provides to us. Management does not believe that cessation of these services would have a material impact on our operations.

As to all of these matters, see also “Risk Factors—Risks Relating to Our Business—Calpine’s recent bankruptcy filing may adversely affect us in several respects” for a further discussion of the potential risks relating to Calpine’s bankruptcy. We have engaged bankruptcy counsel to monitor this proceeding and advocate our interests as necessary and have initiated plans to mitigate the operational risks presented by the Calpine bankruptcy.

We believe the structure of the equity offering of our common stock and the process followed by Calpine allowed market action to determine the $1.05 billion in proceeds, before fees and expenses, received by Calpine in the acquisition. Senior management of Calpine, in consultation with its various advisors, structured the acquisition and the private issuance of our common stock to fund the acquisition. Our equity was purchased by sophisticated investors knowledgeable in oil and natural gas transactions.

Transfers Pending at Calpine’s Bankruptcy

At July 7, 2005, we retained approximately $75 million of the purchase price in respect to properties identified as requiring third party consents that were not received before closing. Subsequent analysis determined that a portion of these properties, with an approximate allocation value of $29 million, under the purchase and sale agreement with Calpine (“PSA”) did not require consent. For that portion of the properties for which third party consents were in fact required having an approximate value of $39 million under the PSA and those properties that did not require consent, we believe that Calpine was obligated to have transferred to us the record title, free of any mortgages, for all properties for which any required consents were received or were otherwise cured at the close of each month for the first six months after closing by no later than 5 days after the end of each month of cure.

The approximate allocated value under the PSA for the portion of these properties subject to a preferential right is $7.1 million. We will retain $7.4 million for the properties subject to this preferential right, which total amount includes approximately $0.3 million for a property which was transferred to us but will be transferred to the appropriate third party under an exercised preferential purchase right.

We believe all conditions for our receipt of record title, free of any mortgages for all of these properties (excluding that portion of these properties subject to this preferential right) were satisfied on or before December 15, 2005. We believe we are the equitable owner of all of these properties (excluding that portion of these properties subject to this preferential right) and that same are not part of Calpine’s bankruptcy estate. Upon our receipt from Calpine of record title, free of any mortgages, we are prepared to pay Calpine approximately $68 million, subject to appropriate adjustment for the associated net revenues for the cured non-consent properties through December 15, 2005. Rosetta’s statement of operations for the six months ended December 31, 2005 does not include any net revenues or production from these properties (excluding that portion of these properties subject to this preferential right).

If Calpine does not provide us with record title, free of any mortgages for all of these properties (excluding that portion of these properties subject to this preferential right), we will have a total of approximately $68 million available to us for general corporate purposes, including for the purpose of acquiring additional

 

4


Table of Contents
Index to Financial Statements

properties. We will also have approximately $7.4 million for that portion of these properties subject to a preferential right, available to us for general Corporate purposes, including for the purpose of acquiring additional properties.

In addition, as to certain of the properties we purchased from Calpine and paid Calpine for on July 7, 2005, we will seek additional documentation from Calpine to eliminate any issue as to the clarity of our ownership. The specific nature of our request will depend on the particular facts and circumstances surrounding each property involved. Certain of these properties are subject to ministerial governmental action approving us as qualified assignee and operator, even though in most cases Calpine specifically conveyed the property to us free and clear of mortgages and liens previously recorded by Calpine’s creditors. As to certain other properties, the documentation delivered by Calpine at closing was incomplete. We remain hopeful that we will be able to work cooperatively with Calpine to secure these ministerial governmental approvals and to accomplish the curative corrections for all of these properties. In addition, as to all these properties, Calpine contractually agreed to provide us with such further assurances as we may reasonably request. Nevertheless, as a result of the recency of Calpine’s bankruptcy filing, it remains uncertain as to how, when and if Calpine will respond cooperatively. If Calpine does not fulfill its contractual obligations and does not complete the documentation necessary to resolve these conveyancing issues, we will pursue all available remedies, including but not limited to a declaratory judgment to enforce our rights and actions to quiet title. After pursuing these matters, if we experience a loss of ownership with respect to these properties without receiving adequate consideration for any resulting loss to us, an outcome our management considers to be remote, then we could experience losses which could have a material adverse effect on our assets, financial condition, earnings and statement of cash flows.

RESTATEMENT OF FINANCIAL RESULTS FOR THIRD QUARTER 2005

In connection with the preparation of our audited financial statements for the six-months ended December 31, 2005, we determined that certain costs of $1.1 million incurred in connection with our issuance of common stock in the third quarter 2005 were incorrectly accounted for as a reduction of the proceeds from such issuance in additional paid-in capital on our balance sheet and should initially have been accounted for as operating expenses on our income statement. In addition, we had over accrued certain costs of $0.1 million in additional paid-in capital. As a consequence, we have restated our financial results for the fiscal quarter ended September 30, 2005, as included in the Selected Data—Quarterly Information included herein, from what we previously disclosed in our registration statement on Form S-1 (333-128888), specifically in our Selected Financial Data, our Historical Unaudited Pro Forma Financial Data, and our unaudited consolidated financial statements as of September 30, 2005 and for the three months ended September 30, 2005.

The changes to correct the error are as follows:

 

    General and administrative costs are increased by $1.1 million;

 

    Net income for third quarter 2005 is reduced by $1.1 million to $8.2 million; and

 

    Earnings per share basic and diluted are reduced by $0.03 and $0.02 to $0.16 and $0.16 per share, respectively.

 

    Additional paid-in Capital is increased by $1.1 million to $748.6 million;

 

    Retained earnings are reduced by $1.1 million to $8.2 million.

See Selected Data—Quarterly Information for the restated financial data.

OUR OPERATING AREAS

We own, subject to the pending transfers above, producing and non-producing oil and natural gas properties in the Sacramento Basin of California, the Lobo and Perdido Trends in South Texas, the State Waters of Texas,

 

5


Table of Contents
Index to Financial Statements

the Gulf of Mexico, the Rocky Mountains and Other located in various geographical areas in the United States. In each area, we are pursuing geological objectives and projects that are consistent with our technical expertise. Our strength and strategies, as discussed above, which include this technical expertise, are concentrated in these particular areas and fields in order to provide the highest potential economic returns. Since the date of our acquisition, we have drilled 29 gross and 19.8 net wells, of which 83% found commercial quantities of production. The following is a summary of our major operating areas in which we discuss their various characteristics. With respect to acreage information in this report, we have included acreage relating to properties which were not transferred to us on the original date of acquisition because consents to transfer had not been obtained at that time. That information is not available without undue time and expense as of the date of this report.

California-Sacramento Basin

Rio Vista Field and Surrounding Area. The Rio Vista Gas Unit and a significant portion of the deep rights below the Rio Vista Gas Unit, which together constitute the greater Rio Vista Field, the largest onshore natural gas field in California and one of the 15 largest natural gas fields in the United States. The field has produced a cumulative 3.6 Tcfe of natural gas reserves to date since its discovery in 1936. The California Energy Commission assigns 419 Bcf of remaining reserves to Rio Vista field. We currently produce or have behind-pipe reserves in over 16 different zones at depths ranging from 2,500 feet to 9,600 feet in the field. The natural gas field trap is a faulted, downthrown rollover anticline, elongated to the northwest. The current productive area is approximately ten miles long and nine miles wide. A majority of the reservoirs are depletion driven with long production histories. For the six months ended December 31, 2005 (the period after our acquisition), the average net daily production in the Sacramento Basin was approximately 29 MMcfe/d from 167 producing wells. As of December 31, 2005, we owned approximately 62,000 net acres in the Rio Vista Field and surrounding Sacramento Basin areas. We are the single largest producer and leaseholder in the basin. Our acreage in the basin holds significant low-risk, low-cost upside potential in 140 currently shut-in or idle wells, 34 proved drilling locations, and numerous workover and recompletion projects. Additional reserve potential exists in gathering system optimization projects, numerous fracture stimulation opportunities in lower permeability, low contrast pays, and deeper gas bearing sands.

Sacramento Valley Extension. We believe our existing land position and financial strength will give us the ability to rapidly expand our Sacramento Basin operations. The Sacramento Valley Extension Project is an extension of work and study done in the redevelopment of the Rio Vista Field and non-operated drilling in nearby reservoirs. Numerous plays are being evaluated, including Mokelumme gorge traps and McCormick fault traps, deeper Winters traps, and shallow Emigh/Capay truncation traps on the east side of the Sacramento Basin. Subtle low contrast and low resistivity pays in the Emigh, Capay, Hamilton and Martinez formations are being pursued for under-exploited and unrecognized potential. Over 50 leads and prospects have been catalogued to date and we have identified more than 80 wells which we believe contain bypassed pay. We have approximately 520 square miles of 3-D seismic data and over 1,800 miles of 2-D seismic data in Rio Vista, the extension area, and the greater Sacramento Valley. The area contains 16 prospective producing formations with historically high production rates at shallow to moderate drill depths. These characteristics, along with an expedited regulatory and permitting process, high reserves per well, and a strong local natural gas market should provide for attractive returns on investments.

Other Activities. We are actively pursuing additional lease acquisitions. Since the date of acquisition, we have added 12,658 acres to our leasehold inventory and are in the process of leasing an additional 9,500 acres. We have contracted drilling rigs which has allowed us to drill seven of the 40 wells in the 2005-2006 drilling program since November 2005 with a 100% success rate. Of the remaining 33 wells to be drilled, three are deep wells below 10,000 feet, one of which is currently in progress. There is one completion rig currently working on Rosetta properties in the Rio Vista Field area, and it has performed 14 recompletions since June 30, 2005. We will add a second completion rig during the second quarter of 2006 to help with the remaining 33 recompletions that are planned for 2006.

 

6


Table of Contents
Index to Financial Statements

Lobo

Lobo Trend. Discovered in 1973, the Lobo Trend of South Texas is a complex, highly faulted sand that has produced over 7 Tcf of natural gas. The Lobo section produces from tight sands with low permeabilities and high pressures at depths of 7,500 to 10,000 feet. We are a significant producer in the Lobo Trend, with over 60,000 net acres, 81 square miles of 3-D seismic, approximately 220 active operated wells and interests in approximately 100 non-operated wells. We recently added a very prospective 4,500 net acre position in the heart of the Lobo play. For the six months ended December 31, 2005, our average net production from the Trend was 21 MMcfe/d. Our working interests range from 50% to 100%. We have identified 84 potential drilling locations on our acreage.

We completed 41 workover projects in 2005. Additional compression is being put in place to accommodate the expected increase in gas production as a result of these well work projects. We have two drilling rigs under contract and we plan to drill 15 wells in the Trend in 2006.

Perdido

Perdido Sand Trend. We own a 50% non-operating working interest in approximately 20,000 acres in the Perdido Sand Trend. The Perdido Sands are in isolated fault blocks and are stratigraphically trapped below the Upper Wilcox structures. The Perdido section is comprised of tight natural gas sands requiring significant fracture stimulation. Horizontal drilling has been very successful in maximizing natural gas recovery. The primary potential in the Perdido is from 9,500 to 12,000 feet. For the six months ended December 31, 2005, our average net daily production was 8.2 MMcfe/d from 27 producing wells. Since June 30, 2005, 48 additional locations have been identified and three successful wells have been drilled. We plan to drill 10 wells in 2006.

Gulf of Mexico

Federal Waters. Subject to pending MMS approval of the conveyances made by Calpine to us at closing, we own and believe we have satisfied the regulators requirements to earn operating rights in seven blocks in the Gulf of Mexico. For the six months ended December 31, 2005, our average net production from these blocks was 5.4 MMcfe/d, which was affected by Hurricanes Katrina and Rita. As the recovery process from the hurricanes nears completion, our average net production from these blocks was 12.3 MMcfe/d for February 2006. We have operated and non-operated working interests in these blocks ranging from 20% to 100%. Production from these working interests represents approximately 10% of Rosetta’s total current production.

We have entered into an area of mutual interest agreement in which we have the right to participate in up to a 50% working interest in wells within 150 OCS blocks on the Louisiana offshore shelf. Over the next three years, we intend to participate in the drilling of at least ten new prospects in these blocks.

Through our participation in a joint venture, we have contracted to acquire a 25% non-operated working interest in two offshore blocks, Main Pass Block 118 and Main Pass Block 117. Main Pass Block 118 well No. 1 was drilled, production casing set, successfully tested and is awaiting platform installation. The Block 117 well No. 1 will spud in the first half of 2006.

State Waters of Texas

We are exploring in the Vicksburg and Frio trends in Galveston Bay, Texas, specifically pursuing sands that exhibit strong hydrocarbon indicators on 3-D seismic. In January 2005, we drilled and operated a discovery well in the Vicksburg Sand. Two additional intervals are present in the well, which have log characteristics that indicate productive zones. We expect to acquire and drill two to three prospects in this trend in the next 12 months with additional wells planned in 2007.

We have acquired a 7% non-operating working interest in the TB-2 prospect in Galveston Bay. The State Tract 251 well No. 5 completed drilling in February 2006 and tested at 4.9 MMcfe/d.

 

7


Table of Contents
Index to Financial Statements

We will participate in an additional exploratory well which we will begin drilling in the first quarter of 2006.

Other Onshore

Live Oak County Prospect. Through the interpretation of 3-D seismic data, we have identified four structures at approximately 16,500 feet in the Sligo Reef Trend in Live Oak County, Texas. Two of these structures were previously drilled and produced by other operators. One structure has produced 33 Bcfe since 1983 from one well on the south end of our 3-D data coverage, and a second structure on the north end of our data coverage produced 12 Bcfe since 1987, also from one well. We currently have approximately 2,500 net acres under lease and plan to obtain a suitable industry partner(s) to join in the drilling of the initial test well to evaluate our prospect.

Frio, Vicksburg, Yegua and Wilcox Trends. In the Frio Trend, the Dunn Peach discovery well was drilled in 2004 on Padre Island in Kleberg County, Texas. Two more development wells and one exploratory dry hole were drilled in 2005. A fifth well was drilled and logged in December 2005 and is currently on production. Two additional development wells will be drilled in 2006. In Colorado County, we are pursuing amplitude plays between 3,500 and 7,000 feet in the Frio and Yegua trends. In the Wilcox, we are pursuing normally pressured structural closures at 10,000 feet and over-pressured closures from 14,000 to 17,500 feet. All of these projects are based on high quality 3-D seismic data. As of December 31, 2005, we have eight prospects in the Frio, Yegua and Upper Wilcox trends of Colorado County, Texas, with six wells expected to be drilled within the next twelve months. We are pursuing numerous additional opportunities in these trends.

Colorado County Prospect. In January 2006, we completed drilling a lower Wilcox prospect in Colorado County, Texas, which resulted in a dry hole.

Rocky Mountains

We are active in the DJ, Uinta and the San Juan Basins in the Rocky Mountains.

DJ Basin, Colorado. As of December 31, 2005, we had a majority working interest in approximately 52,000 net acres, identified 17 drillable, 3-D seismic-supported, 80-acre locations on these lands that have been approved for 40-acre spacing and drilled 16 other locations during the year. We expect to drill approximately 213 additional locations on our existing leases and other leases currently under negotiation with 70 wells planned for 2006. Additional leasing has added approximately 18,500 acres to our land position.

By December 31, 2005, we had acquired 17.1 square miles of 3D seismic data with an additional 38 square miles currently in the process of acquisition. We are using 3-D seismic data as a critical tool in identifying potential drilling opportunities. We recently upgraded the gathering infrastructure and installed new 4” and 6” production lines with compression to enlarge the gathering system and allow us to deliver larger volumes of gas.

Uinta Basin, Utah. We are pursuing plays in the Uinta Basin in the emerging Mesa Verde and Wasatch basin-centered natural gas play in eastern Utah. This play is similar to that in the adjacent Piceance Basin, where we had significant success in the past. Average producing depth is approximately 6,500 feet. As of December 31, 2005, we own a 100% working interest in approximately 2,800 net acres as a result of the acquisition of an additional 626 net acres in the Utah State lease sale. We have identified 35 drillable locations and plan to drill six wells in 2006.

San Juan Basin, New Mexico. The San Juan Basin is the second most prolific gas basin in North America, according to published articles, with 34 Tcf of production, 14 Tcf of which comes from the Fruitland Coal CBM (“Coal Bed Methane”). There is Fruitland Coal production from depths of 1,600 feet surrounding our leasehold. We are pursuing this coalbed methane play and had, as of December 31, 2005, a 100% working interest position

 

8


Table of Contents
Index to Financial Statements

in approximately 6,800 acres. Since then, 640 acres have been added to our leasehold in this play. The well permitting process is underway and we plan to begin our 26-well program by the middle of this year. We have identified 44 drillable locations on our San Juan Basin leases.

Texas Panhandle—Price Ranch Project. On February 10, 2006, we acquired a farmout from BP on approximately 12,800 acres in Sherman County, Texas, to explore for oil and gas reserves in the Marmaton Limestone and Morrow Sandstone. The acreage is held by production by shallower Chase Formation Hugoton gas production. The farmout includes access to a proprietary BP 22 square miles of 3D seismic survey, which is being reprocessed for prospect development. We recently acquired a 3.5-mile 2D seismic line to evaluate several well locations offsetting existing Marmaton production. Further seismic and geologic evaluations are ongoing.

CRUDE OIL AND NATURAL GAS OPERATIONS

Production by Operating Area

The following table presents certain information with respect to our production data for the periods presented:

 

     Successor(1)    Predecessor
     Six Months Ended December 31, 2005    Six Months Ended June 30, 2005
     Natural Gas
(Bcf)
   Oil
(MMBbls)
   Equivalents
(Bcfe)
   Natural Gas
(Bcf)
   Oil
(MMBbls)
   Equivalents
(Bcfe)

California

   5.2    —      5.3    6.5    —      6.6

Lobo

   3.8    —      3.9    3.7    0.0    3.9

Perdido

   1.5    —      1.5    1.8    0.0    1.8

State Waters

   0.7    —      0.7    0.3    —      0.3

Gulf of Mexico

   0.4    0.1    1.0    1.1    0.1    1.5

Other Onshore

   0.7    0.1    0.9    1.0    0.1    1.3

Rocky Mountains

   —      —      —      —      —      —  

Mid-Continent

   0.1    —      0.2    0.1    —      0.1
                             

Totals

   12.4    0.2    13.5    14.5    0.2    15.5
                             

(1) Excludes properties not conveyed as part of the acquisition of the domestic oil and natural gas properties of Calpine, as described in the footnotes on the next page.

Proved Reserves

There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Therefore, the reserve information in this report represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.

As of December 31, 2005, we had 359 Bcfe of proved oil and natural gas reserves, including 344 Bcf of natural gas and 2,481 MBbls of oil and condensate. Using prices as of December 31, 2005, the estimated present value of future net revenues from proved reserves before income taxes, using SEC pricing guidelines, and

 

9


Table of Contents
Index to Financial Statements

discounted at an annual rate of 10% was approximately $1.3 billion. The following table sets forth by operating area a summary of our estimated net proved reserve information as of December 31, 2005:

 

     Estimated Proved Reserves at December 31, 2005(1)(3)(4)
     Developed
(Bcfe)
   Undeveloped
(Bcfe)
   Total
(Bcfe)
   Percent
of Total
Reserves
    PV-10
(Millions)(2)

California

   110.5    37.2    147.7    41 %   $ 605.7

Lobo

   74.0    77.2    151.2    42 %     463.1

Perdido

   9.2    1.0    10.2    3 %     44.1

State Waters

   3.4    —      3.4    1 %     17.8

Gulf of Mexico

   12.7    3.9    16.6    5 %     99.6

Other Onshore

   15.9    7.7    23.6    6 %     76.5

Rocky Mountains

   2.5    1.0    3.5    1 %     9.7

Mid-Continent

   2.3    0.5    2.8    1 %     10.2
                           

Total

   230.5    128.5    359.00    100 %   $ 1326.7
                           

(1) These estimates are based upon a reserve report prepared by Netherland Sewell & Associates, Inc. (hereafter “Netherland Sewell”) using criteria in compliance with SEC guidelines and excludes 19.6 Bcfe of proved oil and gas reserves and a value of $72.5 million representing the total allocated value of wells and the associated leases described in footnote 3 below.

 

(2) Our PV-10 value has been calculated using a spot market natural gas price and posted oil price at December 31, 2005 of $10.08/MMBtu and $57.75/Bbl, respectively, adjusted for basis differentials and held flat for the life of the reserves and adjusted for quality differentials.

 

(3) At the July 2005 closing, we withheld $68 million for properties (excluding that portion of the properties subject to the preferential right) which Calpine agreed to transfer to us as part of the acquisition but for which Calpine had not then secured consents to assign. Subsequent analysis determined that a portion of these properties, having an allocated value withheld under the PSA at closing of $29 million, did not require consent. Consents now have been received for the remaining properties as to which the allocated value under the PSA withheld at closing, was $39 million (“Cured Non-consent Properties”). We are prepared to pay Calpine the retained portion of the original purchase price, upon our receipt from Calpine of record title on these properties, free of any encumbrance, subject to appropriate adjustment for the net revenues through December 15, 2005 related to these properties.

 

(4) Includes properties subject to additional documentation or completion of ministerial actions by federal or state agencies necessary to perfect title issues discovered during routine post-closing analysis after completion of our acquisition of the domestic oil and natural gas business from Calpine, for which Calpine is contractually obligated to assist in resolving.

 

10


Table of Contents
Index to Financial Statements

Operating Data

The following table presents certain information with respect to our production and operating data for the periods presented, all of which is domestic production.

 

     Successor    Predecessor
     Six Months
Ended
December 31,
   Six Months
Ended
June 30,
  

Years

Ended
December 31,

     2005    2005    2004    2003

Production

           

Natural gas (Bcf)

     12.4      14.5      37.3      49.6

Oil (MMBbls)

     0.2      0.2      0.6      0.4

Equivalents (Bcfe)

     13.5      15.5      40.9      52.2

Average realized sales price per unit

           

Natural gas ($/Mcf)(1)

   $ 9.57    $ 6.59    $ 6.02    $ 5.38

Oil ($/Bbl)

   $ 59.52    $ 49.86    $ 39.05    $ 29.67

Equivalents ($/Mcfe)

   $ 8.38    $ 6.70    $ 6.06    $ 5.36

Expenses ($/Mcfe)

           

Lease operating expense(2)

   $ 1.16    $ 1.08    $ 0.75    $ 0.57

Transportation, treating and marketing fees

   $ 0.20    $ 0.19    $ 0.13    $ 0.15

General and administrative, net(3)

   $ 1.09    $ 0.63    $ 0.48    $ 0.32

Depreciation, depletion and amortization
(excluding ceiling test write-downs and impairment)

   $ 3.00    $ 1.98    $ 2.00    $ 1.39

 


(1) The average realized natural gas sales price per Mcf inclusive of the effects of hedging for the six months ended December 31, 2005 was $8.23. There were no other hedging arrangements during any other period presented.

 

(2) The six months ended December 31, 2005 (successor) includes workover expense, ad valorem taxes and insurance of $0.22 per Mcfe, $0.25 per Mcfe and $0.04 per Mcfe, respectively. The high rate of workover expense relates to the workover of our High Island #A-442 well and an aggressive rehabilitation program to boost production on existing wells. The six months ended June 30, 2005 (predecessor) includes workover expense, ad valorem taxes and insurance of $0.22 per Mcfe, $0.22 per Mcfe, and $0.06 per Mcfe, respectively. Ad valorem taxes for the six months ended June 30, 2005 (predecessor) includes higher taxes in South Texas and a special reclamation tax in California. Lease operating expense for 2004 (predecessor) includes workover expense and ad valorem taxes of $0.04 per Mcfe and $0.15 per Mcfe, respectively. Lease operating expense for 2003 (predecessor) includes workover expense and ad valorem taxes of $0.04 per Mcfe and $0.09 per Mcfe, respectively.

 

(3) Net of overhead reimbursements received from other working interest owners.

 

11


Table of Contents
Index to Financial Statements

2005 Capital Expenditures

The following table summarizes information regarding historical capital expenditures for the six months ended December 31, 2005 (successor), the six months ended June 30, 2005 (predecessor) and the historical capital expenditures for the year ended December 31, 2004 (predecessor).

 

    Successor    Predecessor
    Six Months
Ended
December 31,
2005
  

Six Months
Ended
June 30,

2005

  

Year

Ended
December 31,
2004

         (In thousands)     

Development capital expenditures:

       

Sacramento Basin

  $ 3,930    $ 4,166    $ 6,025

Lobo

    6,775      2,001      8,670

Perdido

    9,268      10,874      7,422

Texas State Waters

    2,499      —        —  

Other Onshore

    3,833      1,337      5,164

Gulf of Mexico

    2,947      246      1,813

Rocky Mountains

    3,035      965      —  

Mid-Continent

    317      220      300
                   

Total development capital expenditures

    32,604      19,809      29,394

Exploration capital expenditures:

       

Exploration activities:

       

Sacramento Basin

    3      406      2,214

Lobo

    —        19      —  

Perdido

    —        1,567      11,261

Texas State Waters

    524      3,417      —  

Other Onshore

    6,998      963      3,043

Gulf of Mexico

    6,422      4,310      2,361

Rocky Mountains

    —        137      —  

Mid-Continent

    —        —        —  

Leasehold

    9,224      2,617      3,559

New acquisitions

    5,524      —        —  

Delay rentals

    143      443      507

Geological and geophysical/Seismic

    5,659      513      199
                   

Total exploration capital expenditures

    34,497      14,392      23,144
                   

Total capital expenditures(1)

  $ 67,101    $ 34,201    $ 52,538
                   

(1) The amount for 2004 (predecessor) excludes $1.3 million of capitalized interest, $3.1 million of overhead, $10.0 million of compressor station and gathering system expense and $1.4 million for acquisition properties. Our total capital expenditures in 2004 of $52 million, including these exclusions, corresponds to 2004 total capital costs of $69 million as defined under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” in the Supplemental Oil and Gas Disclosure under Item 8 of this report. The six-month period ended June 30, 2005 (predecessor) excludes $(0.7) million of capitalized interest and $1.7 million of overhead. Capital expenditures for the six months ended December 31, 2005 (successor) excludes capitalized interest of $0.6 million, corporate other of $1.6 million and geological and geophysical costs of $1.7 million. Corporate other consists of corporate costs related to IT software/hardware, office furniture and fixtures and license transfer fees.

 

12


Table of Contents
Index to Financial Statements

Productive Wells and Acreage

The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we own a working interest as of December 31, 2005. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and that are capable of producing oil or natural gas.

 

     Undeveloped Acres(1)    Developed Acres(1)    Productive Wells
     Gross    Net    Gross    Net    Gross    Net

California

   28,266    23,362    47,160    38,646    185    173

Colorado

   65,724    54,322    774    640    18    18

Montana

   41,190    38,721    255    240    2    1

Offshore(3)

   5,512    5,000    23,996    21,765    15    12

Texas

   46,635    24,007    95,022    48,916    503    252

Wyoming

   38,137    37,539    2    2    —      —  

Other(2)

   81,465    76,375    30,883    8,543    99    31
                             

Total

   306,929    259,326    198,092    118,752    822    487
                             

(1) Acreage relating to properties which were not transferred to us on the original date of acquisition because consents to transfer had not been obtained at that time is included in this table. The information to separate acreage on these properties is not available without undue time and expense as of the date of this report.

 

(2) We will not develop our acreage in Kansas and Missouri and we will let the relevant leases expire in accordance with their terms. No cost was allocated to these leases in the acquisition of the oil and natural gas properties from Calpine.

 

(3) Offshore productive wells are based on intervals rather than well bores.

The following table shows our interest in undeveloped acreage as of December 31, 2005 which is subject to expiration in 2006, 2007, 2008, and thereafter.

 

2006

   2007    2008    Thereafter

Gross

   Net    Gross    Net    Gross    Net    Gross    Net
37,935    33,279    77,214    73,032    25,369    20,351    166,411    132,664

Drilling Activity

The following table sets forth the number of gross exploratory and gross development wells drilled in which we participated during the last three fiscal years. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. Productive wells are either producing wells or wells capable of commercial production. At December 31, 2005, we were in the process of drilling ten gross wells (6.0 net).

 

     Exploratory    Development
     Productive    Dry    Total    Productive    Dry    Total

2005

   7.0    5.0    12.0    41.0    3.0    44.0

2004

   8.0    2.0    10.0    40.0    2.0    42.0

2003

   17.0    8.0    25.0    20.0    5.0    25.0

 

13


Table of Contents
Index to Financial Statements

The following table sets forth, for each of the last three fiscal years, the number of net exploratory and net development wells drilled by us based on our proportionate working interest in such wells.

 

     Exploratory    Development
     Productive    Dry    Total    Productive    Dry    Total

2005

   3.4    3.4    6.8    23.5    3.0    26.5

2004

   4.3    1.0    5.3    21.1    2.0    23.1

2003

   14.0    4.5    18.5    18.5    3.4    21.9

Marketing and Customers

Pursuant to our natural gas purchase and sales contract with Calpine and its existing subsidiaries, we are obligated to sell all of the then-existing and future production from our California leases in production as of May 1, 2005 through December 2009 based on market prices. As of December 31, 2005, this production comprised approximately 42% of our current overall daily equivalent production. Under the terms of our gas purchase and sale contract and spot agreements with Calpine, cash payment for all natural gas volumes that are contractually sold to Calpine on the previous day are deposited into our collateral bank account. If the funds are not deposited one business day in arrears in accordance with our contract, we are not obligated to continue to sell our production to Calpine and these sales can then cease immediately. We would then be in a position to market this natural gas production to other parties. Calpine has 60 days to pay amounts owed to us, at which time we are obligated under the contract to resume natural gas sales to Calpine. We believe that Calpine’s recent bankruptcy will have no significant effect on our ability to sell our natural gas at market prices. Additionally, while we may market our natural gas production, which is not subject to the above mentioned natural gas contract, to parties other than Calpine, an affiliate of Calpine will provide us administrative services in connection with such marketing efforts.

All of our other production is sold to various purchasers, including Calpine, on a competitive basis.

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, and obtaining purchasers and transporters of the oil and natural gas we produce. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing natural gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or abnormally hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas of the Rocky Mountain region. These seasonal anomalies can increase

 

14


Table of Contents
Index to Financial Statements

competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Regulation

The oil and natural gas industry in the United States is subject to extensive regulation by federal, state and local authorities. We hold onshore and offshore federal leases involving the United States Department of Interior (the Bureau of Land Management, the Bureau of Indian Affairs and the Minerals Management Service). At the federal level, various federal rules, regulations and procedures apply, including those issued by the United States Department of Interior as noted above, and the United States Department of Transportation (U.S. Coast Guard and Office of Pipeline Safety). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Varied remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines and penalties or otherwise subject us to the various remedies as are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

Transportation and Sale of Natural Gas. The Federal Energy Regulation Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and service conditions. Although the FERC does not regulate natural gas producers such as us, the agency’s actions are intended to foster increased competition within all phases of the natural gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the natural gas industry will have on our natural gas sales efforts.

The FERC, the United States Congress or state regulatory agencies may consider additional proposals or proceedings that might affect the natural gas industry. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other natural gas producers with which we compete.

Regulation of Production. Oil and natural gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of the spacing, and plugging and abandonment of wells. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

U.S. Minerals Management Services of the Department of the Interior. The Minerals Management Service (“MMS”) has broad authority to regulate our oil and natural gas operations on offshore leases in federal waters. It must approve and grant permits in connection with our drilling and development plans. Additionally, the MMS has promulgated regulations requiring offshore production facilities to meet stringent engineering and construction specifications restricting the flaring or venting of natural gas, governing the plugging and abandonment of wells and controlling the removal of production facilities. Under certain circumstances, the MMS may suspend or terminate any of our operations on federal leases, and has proposed regulations that would permit it to expel unsafe operators from offshore operations. The MMS has also established rules governing the calculation of royalties and the valuation of oil produced from federal offshore leases and regulations regarding costs for natural gas transportation. Delays in the approval of plans and issuance of permits by the MMS because of staffing, economic, environmental or other reasons could adversely affect our operations.

 

15


Table of Contents
Index to Financial Statements

Environmental Regulations. The exploration for and development of geothermal resources, oil, natural gas liquids and natural gas, and the drilling and operation of wells, fields, and gathering systems, are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. These laws and regulations in many cases require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.

Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. If a person violates these environmental laws and regulations and any related permits, he or she may be subject to significant administrative, civil and criminal penalties, injunctions and construction bans or delays. If we were to discharge hydrocarbons or hazardous substances into the environment, we could, to the extent the event is not insured, incur substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws also may impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment.

The environmental laws and regulations, which have the most significant impact on the oil and natural gas exploration and production industry, are as follows:

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an EA prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed EIS that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, affect oil and natural gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as “hazardous wastes”.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws.

 

16


Table of Contents
Index to Financial Statements

Insurance Matters

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows. In analyzing our operations and insurance needs, and in recognition that we have a large number of individual well locations with varied geographical distribution, we compared premium costs to the likelihood of material loss of production. Based on this analysis, we have elected, at this time, not to carry loss of production or business interruption insurance for our operations.

Filings of Reserve Estimates With Other Agencies

During 2005, we filed estimates of our oil and gas reserves for the year 2004 with the Department of Energy for those properties which we operate. These estimates differ by five percent or less from the reserve data presented. For information concerning proved natural gas NGLs and crude oil reserves, see “Supplemental Oil and Gas Disclosures.”

Employees

As of December 31, 2005, we have 111 full time employees. We also contract for the services of independent consultants involved in land, regulatory accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Access to Company Reports

For further information pertaining to us, you may inspect without charge at the public reference facilities of the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549 any of our filings with the SEC. Copies of all or any portion of the documents may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

Corporate Governance Matters

Our website is http://www.rosettaresources.com. All corporate filings with the SEC can be found on our website, as well as other information related to our business. Under the Corporate Governance tab you can find copies of our Code of Business Conduct and Ethics, our Nominating and Corporate Governance Committee Charter, our Audit Committee Charter, and our Compensation Committee Charter.

Item 1A. Risk Factors.

Calpine’s recent bankruptcy filing may adversely affect us in several respects.

Calpine and certain of its subsidiaries (the “Debtors”) filed for protection under the federal bankruptcy laws in the Southern District of New York on December 20, 2005 (the “Petition Date”). The Debtors may bring an action under the Bankruptcy Code or relevant state fraudulent conveyance laws asserting that Calpine’s transfer of its domestic oil and natural gas business to us (as either the initial transferee or the immediate or mediate transferee from the initial transferee) should be voided or set aside as a fraudulent transfer. To prevail in such a legal action, the Debtors would be required to prove that Calpine either:

(i) transferred its domestic oil and natural gas business to us with the intent of hindering, delaying or defrauding its current or future creditors; or

 

17


Table of Contents
Index to Financial Statements

(ii) as of July 7, 2005 (the date of the closing of the acquisition), (a) received less than reasonably equivalent value for the business, and (b) was insolvent, became insolvent as a result of such transfer, was engaged in a business or transaction or was about to engage in a business or transaction for which any property remaining was unreasonably small, or intended to incur or believed it would incur debts that would be beyond its ability to pay as such debts matured.

Our primary defense against such a legal challenge rests on the extensive negotiations leading up to, and the market pricing mechanisms incorporated within the terms of the acquisition. Nonetheless, if after a trial on the merits, the court were to determine that the Debtors have met their burden of proof, it could void the transfer or take other actions against us, including (i) setting aside the acquisition and returning our purchase price and give us a first lien on all the properties and assets we purchased in the acquisition or (ii) sustaining the acquisition subject to our being required to pay the Debtors the amount, if any, by which the fair value of the business transferred, as determined by the court as of July 7, 2005, exceeded the purchase price determined and paid in July 2005. If the bankruptcy court should so rule, a setting aside of the acquisition would be materially detrimental to us in that substantially all our properties would be returned to Calpine, subject to our right (as a good faith transferee) to retain a lien in our favor to secure the return of the purchase price we paid for the properties. Additionally, if the bankruptcy court should so rule, any requirement to pay an increased purchase price could adversely affect us depending on the amount we might be required to pay.

Additionally, at the closing of the acquisition, Calpine agreed to sell but retained title to certain domestic oil and gas properties, subject to obtaining various third party consents or waivers of preferential purchase rights necessary in order to effect transfer of title. In July 2005, as part of the transactions undertaken in connection with closing the acquisition, we accepted possession of and have since been operating all of the properties for which Calpine retained record legal title. We withheld approximately $75 million from the aggregate purchase price, which was the allocated dollar amount under the PSA for the properties. Subsequent to the closing of the acquisition, with the exception of the properties subject to this preferential right, we obtained substantially all of the consents to assign for all of these properties for which consents were actually required. Prior to the Calpine bankruptcy, we were prepared to consummate the assignments of these properties, excepting those subject to the preferential purchase right. The PV-10 value of these properties at December 31, 2005 was approximately $72.4 million. Based on our internal calculations, we estimate the PV-10 value as of March 31, 2006 to be approximately $51.1 million. We are prepared to pay Calpine the retained portion of the original purchase price, approximately $68 million, upon our receipt from Calpine of record title to these properties, free of any encumbrance, and for that portion of these properties which are the cured non-consent properties, subject to appropriate adjustment for the net revenues through December 15, 2005. If the assignment of these properties does not occur, the portion of the purchase price we held back pending consent will be retained by us and will be available to us for general corporate purposes.

In addition, certain of the properties we purchased from Calpine and paid Calpine for on July 7, 2005, require certain additional documentation, depending on the particular facts and circumstances surrounding the particular properties involved, such documentation to be delivered by Calpine to quiet title related to Rosetta’s ownership of these properties. Certain of these properties are subject to ministerial governmental action approving us as qualified assignee and operator, even though in most cases there had been a conveyance by Calpine and release of mortgages and liens by Calpine’s creditors. For certain other properties, the documentation delivered by Calpine at closing was incomplete. While the Company remains hopeful that it will be able to work cooperatively with Calpine to secure these ministerial governmental approvals and accomplish the curative corrections for all of these properties for which the Company paid Calpine for, all of the same being covered, we believe, by the further assurances provision of the parties’ definitive agreements, the exact details for each property involved of how, when and if this will be able to be secured or accomplished continue to remain uncertain at this early stage of Calpine’s bankruptcy.

Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would significantly affect our financial results and impede our growth.

Our revenue, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can significantly

 

18


Table of Contents
Index to Financial Statements

affect our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

 

    domestic and foreign supply of oil and gas;

 

    price and quantity of foreign imports;

 

    actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;

 

    domestic and foreign governmental regulations;

 

    political conditions in or affecting other oil producing and natural gas producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

 

    weather conditions and natural disasters;

 

    technological advances affecting oil and natural gas consumption;

 

    overall U.S. and global economic conditions; and

 

    price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because the majority of our estimated proved reserves are natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Thus a significant reduction in commodity prices may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition, results of operations and cash flows.

Development and exploration drilling activities do not ensure reserve replacement and thus our ability to produce revenue.

Development and exploration drilling and strategic acquisitions are the main methods of replacing reserves. However, development and exploration drilling operations may not result in any increases in reserves for various reasons. Development and exploration drilling operations may be curtailed, delayed or cancelled as a result of:

 

    lack of acceptable prospective acreage;

 

    inadequate capital resources;

 

    weather conditions and natural disasters;

 

    title problems;

 

    compliance with governmental regulations;

 

    mechanical difficulties; and

 

    availability of equipment.

Counterparty credit default could have an adverse effect on us.

Our revenues are generated under contracts with various counterparties. Results of operations would be adversely affected as a result of non-performance by any of these counterparties of their contractual obligations under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the counterparty, or due to

 

19


Table of Contents
Index to Financial Statements

circumstances caused by other market participants having a direct or indirect relationship with the counterparty. Defaults by counterparties may occur from time to time, and this could negatively impact our results of operations, financial position and cash flows. Calpine’s recent bankruptcy could result in the failure of Calpine to continue purchasing natural gas from us under our natural gas purchase and sale agreements with Calpine discussed below.

We sell a significant amount of our production to one customer.

In connection with the acquisition, we entered into a natural gas purchase and sale contract with Calpine that obligates us to sell all of the then-existing and future production from our California leases in production as of May 1, 2005 through December 2009 based on market prices. As of December 31, 2005, this production comprised approximately 42% of our current overall production based on an equivalent basis. Calpine’s recent bankruptcy could result in failure of Calpine to continue purchasing natural gas from us. Additionally, under separate monthly spot agreements, we may sell our natural gas production, not subject to the term contract to Calpine, which could increase our credit exposure to Calpine. Under the terms of our natural gas purchase and sale contract and spot agreements with Calpine, all natural gas volumes that are contractually sold to Calpine are collateralized by Calpine making daily margin payments to our collateral account equal to the previous day’s natural gas sales. In the event of a default by Calpine, we could be exposed to the loss of up to four days of natural gas sales revenue under the contract, which at prices and volumes in effect as of December 31, 2005 would be approximately $1.4 million.

Unless we replace our oil and natural gas reserves, our reserves and production will decline.

Our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be affected adversely. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.

Future projects and acquisitions may depend on our ability to obtain financing beyond our cash flow from operations. We will finance our business plan and operations primarily with internally generated cash flow, bank borrowings, entering into exploratory arrangements with other parties and privately raised equity. In the future, we will require substantial capital to fund our business plan and operations. Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.

The terms of our credit facilities contain a number of restrictive and financial covenants that limit our ability to pay dividends. If we are unable to comply with these covenants, our lenders could accelerate the repayment of our indebtedness.

The terms of our credit facilities subject us to a number of covenants that impose restrictions on us, including our ability to incur indebtedness and liens, make loans and investments, make capital expenditures, sell assets, engage in mergers, consolidations and acquisitions, enter into transactions with affiliates, enter into sale and leaseback transactions, change our lines of business and pay dividends on our common stock. We will also be required by the terms of our credit facilities to comply with financial covenant ratios. A more detailed description of our credit facilities is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and the footnotes to the consolidated/combined financial statements.

 

20


Table of Contents
Index to Financial Statements

A breach of any of the covenants imposed on us by the terms of our indebtedness, including the financial covenants under our credit facilities, could result in a default under such indebtedness. In the event of a default, the lenders for our revolving credit facility could terminate their commitments to us, and they and the lenders of our second lien term loan could accelerate the repayment of all of our indebtedness. In such case, we may not have sufficient funds to pay the total amount of accelerated obligations, and our lenders under the credit facilities could proceed against the collateral securing the facilities. Any acceleration in the repayment of our indebtedness or related foreclosure could adversely affect our business.

Properties we acquire may not produce as expected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects; however, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on higher value properties or properties with known adverse conditions and will sample the remainder.

However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our exploration and development activities may not be commercially successful.

Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

    unexpected drilling conditions; pressure or irregularities in formations; equipment failures or accidents;

 

    adverse weather conditions, including hurricanes, which are common in the Gulf of Mexico during certain times of the year; compliance with governmental regulations; unavailability or high cost of drilling rigs, equipment or labor;

 

    reductions in oil and natural gas prices; and

 

    limitations in the market for oil and natural gas.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, results of operations and financial position.

Numerous uncertainties are inherent in our estimates of oil and natural gas reserves and our estimated reserve quantities and present value calculations may not be accurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the estimated quantities and present value of our reserves.

Estimates of proved oil and natural gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum engineers and geologists. There are numerous uncertainties inherent in

 

21


Table of Contents
Index to Financial Statements

estimating quantities of proved oil and natural gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices and expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of oil and natural gas. Actual future production, revenue, taxes, development expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein. In addition, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The present value of future net revenues from our proved reserves referred to in this Report is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming royalties to the Minerals Management Service (“MMS”), royalty owners and other state and federal regulatory agencies with respect to our affected properties, will be paid or suspended for the life of the properties based upon oil and natural gas prices as of the date of the estimate. Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.

The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and natural gas industry, in general, will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.

We are subject to complex government regulation that could adversely affect our operations.

Our activities are subject to complex and stringent environmental and other governmental laws and regulations. The exploration and production of oil and natural gas requires numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, including state and local agencies in California, whose regulations typically are more stringent than in other states or localities, as well as compliance with environmental protection legislation and other regulations. We remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations are routinely revised or reinterpreted, and new laws and regulations may become applicable to us that could have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.

Our business is subject to federal, state and local laws and regulations as interpreted by governmental agencies and other bodies, including those in California, vested with much authority relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. Existing laws and regulations are routinely changed, and any changes could increase costs of compliance and costs of operating drilling equipment or significantly limit drilling activity.

Under certain circumstances, the MMS may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. The requirements imposed by these laws and regulations are frequently changed and

 

22


Table of Contents
Index to Financial Statements

subject to new interpretations, and if such were to occur, could negatively impact our results of operations and cash flows.

Our business requires technical expertise, specialized knowledge and training and a high degree of management experience.

Our success is largely dependent on the skills, experience and efforts of our employees. The loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business, financial conditions and results of operations and future growth.

Our results are subject to commodity price fluctuations related to seasonal and market conditions and reservoir and production risks.

Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including:

 

    seasonal variations in oil and natural gas prices;

 

    variations in levels of production; and

 

    the completion of exploration and production projects.

The ultimate outcome of the legal proceedings relating to our activities cannot be predicted. Any adverse determination could have a material adverse effect on our financial condition, results of operations or cash flows.

Operation of our properties has generated various litigation matters arising out of the normal course of business. In connection with the transfer and assumption agreement with Calpine, we generally assumed liabilities arising from our activities from and after July 7, 2005 for and defense of future litigation and claims involving Calpine’s domestic oil and natural gas reserves that we acquired in the acquisition, other than certain litigation that Calpine and its subsidiaries retained by agreement. Calpine’s recent bankruptcy may affect these retained claims. The ultimate outcome of claims and litigation relating to our activities cannot presently be determined, nor can the liability that may potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result, these matters may potentially be material to our financial condition, results of operations or cash flows.

Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions, the unavailability of satisfactory oil and natural gas processing and transportation or the remote location of certain of our drilling operations may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in natural gas wells or delay initial production for lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors, major and

 

23


Table of Contents
Index to Financial Statements

large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than our resources. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business involves certain operating hazards such as:

 

    well blowouts;

 

    cratering;

 

    explosions;

 

    uncontrollable flows of oil, natural gas or well fluids;

 

    fires;

 

    earthquakes and hurricanes;

 

    pollution; and

 

    releases of toxic gas.

The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.

In addition, our operations in California are especially susceptible to damage from natural disasters such as earthquakes and fires and involve increased risks of personal injury, property damage and marketing interruptions. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, and acquisition, or could result in a loss of our properties. Our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. For example, we are not fully insured against earthquake risk in California because of high premium costs. Insurance covering earthquakes or other risks may not be available at premium levels that justify its purchase in the future, if at all. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

Environmental liabilities could adversely affect our financial condition.

The oil and natural gas business is subject to environmental hazards, such as oil spills, natural gas leaks and ruptures and discharges of petroleum products and hazardous substances, and historic disposal activities. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. In addition, we also may be liable for environmental damages caused by the previous owners or operators of properties we have

 

24


Table of Contents
Index to Financial Statements

purchased or are currently operating. A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:

 

    well drilling or workover, operation and abandonment;

 

    waste management;

 

    land reclamation;

 

    financial assurance under the Oil Pollution Act of 1990; and

 

    controlling air, water and waste emissions.

Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Additionally, our compliance with these laws may, from time to time, result in increased costs to our operations or decreased production, and may affect our costs of acquisitions. We are unable to predict the ultimate cost of complying with these regulations.

In addition, environmental laws may, in the future, cause a decrease in our production or cause an increase in our costs of production, development or exploration. Pollution and similar environmental risks generally are not fully insurable.

Some of our California properties have been in operation for a substantial length of time, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations. A variety of existing laws, rules and guidelines govern activities that can be conducted on our properties and other existing or future laws, rules and guidelines could prohibit or limit our operations and our planned activities for properties.

Under our Purchase and Sale Agreement with Calpine, we are responsible for environmental claims prior to the acquisition and we have no indemnification from Calpine related to those claims.

Our acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.

Our growth strategy includes acquiring oil and natural gas businesses and properties if favorable economics and strategic objectives can be served. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully.

Furthermore, acquisitions involve a number of risks and challenges, including:

 

    diversion of management’s attention;

 

    the need to integrate acquired operations;

 

    potential loss of key employees of the acquired companies;

 

    potential lack of operating experience in a geographic market of the acquired business; and

 

    an increase in our expenses and working capital requirements.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses and properties or realize other anticipated benefits of those acquisitions.

We are vulnerable to risks associated with operating in the Gulf of Mexico.

Our operations and financial results could be significantly impacted by conditions in the Gulf of Mexico because we explore and produce extensively in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the Gulf of Mexico, including those relating to:

 

    adverse weather conditions and natural disasters;

 

25


Table of Contents
Index to Financial Statements
    oil field service costs and availability;

 

    compliance with environmental and other laws and regulations;

 

    remediation and other costs resulting from oil spills or releases of hazardous materials; and

 

    failure of equipment or facilities.

Further, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from fields in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production, and as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

Hedging transactions may limit our potential gains.

We entered into natural gas price hedging arrangements with respect to a significant portion of our expected production through 2009. Such transactions may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement, or the counterparties to our hedging agreements fail to perform under the contracts.

The historical financial results of the domestic oil and natural gas business of Calpine may not be representative of our results as a separate company.

The combined historical financial information included in this report does not necessarily reflect what our financial position, results of operations and cash flows would have been had we been a separate, stand-alone entity during the periods presented. The costs and expenses reflect charges from Calpine for centralized corporate services and infrastructure costs. The allocations were determined based on Calpine’s methodologies. This combined historical financial information is not necessarily indicative of what our results of operations, financial position and cash flows will be in the future.

Failure to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business.

Under current rules of the SEC, as of December 31, 2007, we will be required to document and test our internal control over financial reporting so that our management can certify as to the effectiveness of our internal control over financial reporting and our independent registered public accounting firm can render an opinion on management’s assessment. We cannot be certain as to the timing of completion of our evaluation, testing and remediation actions, if any, or the impact of the same on our operations. The assessment of our internal control over financial reporting will require us to expend significant management and employee time and resources and incur significant additional expense.

We have begun the process of evaluating and documenting our internal control over financial reporting in order to test and determine any remediation actions that may be necessary and to fully implement the requirements relating to internal controls and all other aspects of related SEC rules and the Sarbanes Oxley Act of 2002. Management has begun the process of developing a stand-alone infrastructure and has determined that certain general computer controls, specifically system security and change control procedures associated with the Excalibur accounting system of the oil and natural gas businesses we acquired from Calpine, need to be upgraded for our use. Additionally, management has identified the following material weaknesses as of December 31, 2005: (1) lack of a sufficient complement of permanent personnel to have an appropriate accounting and financial reporting structure to support the activities of the Company and (2) ineffective controls as related to the identification and documentation of accounting policies, including selection and application of generally accepted accounting principles used for accounting for select transactions and other activities. See Item 9A. Controls and Procedures, for a further discussion on these material weaknesses.

 

26


Table of Contents
Index to Financial Statements

We have begun a process of remediating the recognized areas of internal controls that need improvement and have launched corrective actions to meet the required SEC and Sarbanes-Oxley standards. Our efforts may not be successful and additional deficiencies or weaknesses in our internal controls and procedures may be identified.

Our prior and continuing relationship with Calpine exposes us to risks attributable to Calpine’s businesses and credit worthiness.

We acquired a business that previously was integrated within Calpine and is subject to liabilities and risk for activities of businesses of Calpine other than the acquired business. In connection with our separation from Calpine, Calpine and certain of its subsidiaries have agreed to retain certain liabilities. Third parties may seek to hold us responsible for some or all of those retained liabilities. Under our purchase and sale agreement, Calpine and certain of its subsidiaries have agreed to indemnify us for these retained liabilities.

Any claims made against us that are properly attributable to Calpine and certain of its subsidiaries will require us to exercise our rights under the indemnification provisions of the purchase and sale agreement to obtain payment from Calpine and certain of its subsidiaries, as the case may be. We are exposed to the risk that, in these circumstances and in light of the Calpine bankruptcy, any or all of Calpine and certain of its subsidiaries cannot or will not make the required payment. If this were to occur, our business and results of operations, financial position or cash flow could be adversely affected.

If we are unable to obtain governmental approvals arising from the acquisition, we may not acquire all of Calpine’s domestic oil and gas business.

The consummation of the acquisition required various approvals, filings and recordings with governmental entities to transfer existing contracts and arrangements as well as all of Calpine’s domestic oil and gas properties to us. In addition, all government issued permits and licenses that are important to our business, including permits issued by the City of Rio Vista and Counties of Sacramento, Solano and Contra Costa, California, may require reapplication or application by us and reissuance or issuance in our name. If we are unable to obtain a reissuance or issuance of any contract, license or permit being transferred, we have entered into a transition services agreement with Calpine pursuant to which, to the extent possible, we will receive the benefits of the contract, license or permit and will discharge the duties and bear the costs and risks under such contract, license or permit.

The ongoing SEC informal inquiry relating to the downward revision of the estimate of continuing proved reserves, while owned by Calpine, could have a material adverse effect on the presentation of our predecessor financial statements.

In April 2005, the staff of the Division of Enforcement of the SEC commenced an informal inquiry into the facts and circumstances relating to the downward revision of the estimate of continuing proved natural gas reserves at December 31, 2004, while the domestic oil and natural gas properties were owned by Calpine. Calpine has advised us that it is fully cooperating with this informal inquiry which also involved two other non-oil and natural gas related matters, and we have separately agreed with Calpine that we will also fully cooperate. Calpine has advised us that it has not had any further response or inquiry from the SEC staff in regard to this matter since July 2005 and that the ultimate outcome of this inquiry cannot presently be determined. However, it is possible that the staff of the SEC could conclude that the estimate of continuing proved reserves as of December 31, 2004, as revised, requires further downward revision, which could have a material adverse effect on the presentation of our predecessor financial statements.

Future sales of our common stock may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline, which could impair our ability to raise capital through the sale of additional common or preferred stock.

 

27


Table of Contents
Index to Financial Statements

Stock sales and purchases by institutional investors or stockholders with significant holdings could have significant influence over our stock volatility and our corresponding ability to raise capital through debt or equity offerings.

Because institutional investors have the ability to trade in large volumes of shares of our common stock, the price of our common stock could be subject to significant volatility, which could adversely affect the market price for our common stock as well as limit our ability to raise capital or issue additional equity in the future.

You may experience dilution of your ownership interests because of the future issuance of additional shares of our common and preferred stock.

We may in the future issue our previously authorized and unissued equity securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We are currently authorized to issue an aggregate of 155,000,000 shares of capital stock consisting of 150,000,000 shares of common stock and 5,000,000 shares of preferred stock with preferences and rights as determined by our Board of Directors. As of December 31, 2005, 50,585,400 shares of common stock were issued, including 278,000 shares of restricted stock issued to certain employees and directors that vested in 2005 or early in 2006 and 307,400 shares of restricted stock that vest over a three-year period ending in 2008. Pursuant to our 2005 Long-Term Incentive Plan, we have reserved 3,000,000 shares of our common stock for issuance as restricted stock, stock options and/or other equity based grants to employees and directors. Of the reserved shares, 1,233,333 may be awarded as restricted stock and 1,766,667 may be awarded as stock options and/or other equity based grants and includes 706,550 options to purchase common stock issued to certain employees and directors. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future issuance of our securities for capital raising purposes, or for other business purposes.

Provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Our certificate of incorporation and bylaws prohibit our stockholders from taking action by written consent absent approval by all members of our Board of Directors. Further, our stockholders do not have the power to call a special meeting of stockholders.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

Our headquarters are located at 717 Texas, Suite 2800, Houston, Texas 77002, where we sublease two floors of office space from Calpine. We also maintain a division office in Denver, Colorado, where we lease office space from a third party. At acquisition, we were assigned this lease by Calpine who then subleased some office space from us. Calpine subsequently rejected the contract and we now lease our office space directly from a third party. We also have field offices in Laredo, Texas and Rio Vista, California. All leases were negotiated at market prices applicable to their respective location.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions as well as mortgage liens

 

28


Table of Contents
Index to Financial Statements

on at least 80% of our proved reserves in accordance with our credit facilities. We do not believe that any of these burdens materially interferes with our use of the properties in the operation of our business.

Except as noted in the “Transfers Pending at Calpine’s Bankruptcy” section on pages 4 and 5, we believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and natural gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

Calpine’s recent bankruptcy may delay or frustrate our ability to complete additional transfers of properties for which consents were not obtained as of July 7, 2005.

Item 3. Legal Proceedings.

Legal Proceedings

We are involved in various other claims and legal actions arising out of the normal course of our business. We do not anticipate that the outcome of these claims and legal actions will have a material adverse effect on our financial position, results of operations or cash flows.

Calpine Bankruptcy

We have engaged bankruptcy counsel to monitor the Calpine bankruptcy proceeding and advocate our interests as necessary. As of the date of this report, we have not been named as a party to any proceeding or have received any notice to appear with respect to this bankruptcy proceeding. The only significant event affecting us directly has been the approval of the bankruptcy court for Calpine, as debtor-in-possession, to continue payments to us for our delivery of natural gas under our gas purchase and sale agreement.

Item 4. Submission of Matters to a Vote of Security Holders.

No matters were submitted to a vote of our security holders during the fourth quarter of 2005.

Executive Officers of the Registrant.

B. A. Berilgen, has served as Chairman of the Board, President and Chief Executive Officer of Rosetta Resources Inc. since its formation in June 2005. Prior to joining Rosetta, Mr. Berilgen served as Executive Vice President of Calpine Corporation and as President—Calpine Power Fuels Company from January 2003 to June 2005. Previously he served as Senior Vice President—Natural Gas of Calpine Corporation from October 1999 to January 2003. Additionally, since October 1999, Mr. Berilgen served as Executive Vice President of Rosetta Resources Operating LP (formerly known as Calpine Natural Gas L.P.), then a subsidiary of Calpine and the operator of Calpine’s domestic oil and natural gas business. On December 20, 2005, Calpine Corporation and certain subsidiaries filed for bankruptcy protection in the Southern District of New York. Mr. Berilgen was President and Chief Executive Officer of Sheridan Energy, a publicly traded oil and gas company from 1997 to 1999, when Sheridan was acquired by Calpine. Mr. Berilgen previously worked as Vice President of Operations for Forest Oil and has also held positions with Aminoil, ANR Production Company and Mobil during his 35-year career in exploration and production. He holds a Bachelors degree in Petroleum Engineering and a Masters degree in Industrial Engineering, both from the University of Oklahoma.

Michael J. Rosinski, has served as Executive Vice President, Chief Financial Officer, and Treasurer of Rosetta Resources Inc. since July 2005. Prior to joining Rosetta, Mr. Rosinski served as Executive Vice President

 

29


Table of Contents
Index to Financial Statements

and Chief Financial Officer of Rosetta Resources Operating LP (formerly known as Calpine Natural Gas L.P.). Prior to that Mr. Rosinski served as Chief Financial Officer of Power3 Medical Products from July 2004 through May 2005, and was Senior Vice President and Chief Operating Officer of Municipal Energy Resources Corporation from 1997 to 2004. Previously, he held positions as Senior Vice President and Chief Financial Officer of Santa Fe Energy, and held a number of positions at Tenneco. Mr. Rosinski holds a Masters degree in Business Administration from Tulane University and a Bachelors degree in Mechanical Engineering from Georgia Tech. He has over 35 years of experience in energy financing, financial management and controls, planning and investor relations in energy and related industries.

Charles F. Chambers, has served as Executive Vice President, Corporate Development of Rosetta Resources Inc. since June 2005. Prior to joining Rosetta and since February 2005, Mr. Chambers served as Vice President of Business Development and Land for Rosetta Resources Operating LP (formerly known as Calpine Natural Gas L.P.). Prior to that in March 2002, he founded Buena Vista Oil & Gas for the purpose of acquiring domestic oil and gas assets, and he served as its President. Mr. Chambers served as Vice President, Business Development for Rosetta Resources Operating LP from October 1999 until March 2002. Mr. Chambers served as Vice President, Corporate Development of Sheridan Energy from 1997 until 1999 when Sheridan was acquired by Calpine. Prior to these assignments, Mr. Chambers was land manager at C&K Petroleum Inc. and later founded Chambers Oil & Gas, Inc., an independent operator active in the Texas-Louisiana Gulf Coast. Mr. Chambers has 32 years of experience in the oil and gas industry.

Michael H. Hickey, has served as Vice President and General Counsel of Rosetta Resources Inc. since August 2005. Mr. Hickey has previous experience in the role as general counsel having served as Vice President Law and Secretary of Technip Offshore Inc., from April 2004 through July 2005. He is knowledgeable concerning Rosetta’s oil and natural gas business, having been promoted to Vice President and Managing Counsel for Calpine’s North American E&P and midstream group, where he contributed to the growth of these oil and natural gas assets from September 2000 to March 2004. He served as Vice President, General Counsel and Secretary of Kosa B.V. from December 1998 until August 2000. He holds a Bachelors of Arts degree and J.D. both from the University of Tennessee and has been a practicing lawyer for 26 years.

Edward E. Seeman, has served as Vice President, Northern Division of Rosetta Resources Inc. since July 2005. Prior to joining Rosetta, Mr. Seeman served as Director, Reservoir Engineering since April 2001 for Rosetta Resources Operating LP (formerly known as Calpine Natural Gas L.P.). Previously, he held a number of positions with Forest Oil Corporation beginning in 1974. He holds a Bachelors degree in Petroleum Engineering from the University of Oklahoma and has over 31 years of reservoir engineering experience in the oil and gas industry.

 

30


Table of Contents
Index to Financial Statements

PART II

 

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Trading Market

Our common stock is listed on The NASDAQ National Market® under the symbol “ROSE”. Our common stock began trading on February 13, 2006, the date of the effectiveness of our registration of 50,279,000 shares which was a portion of our common stock for resale by our stockholders to the public on a delayed or continuous basis. We do not receive any proceeds from the sales of any of these shares of common stock. Prior to such date, there was no public market for our common stock. However, certain qualified institutional investors participated in limited trading through quotes on The PORTAL Market after July 7, 2005 and through December 31, 2005. The reported last sale price per share of our common stock as quoted through The NASDAQ National Market® on April 10, 2006 was $18.55 per share. As of such date we had 50,587,269 shares outstanding, 362,400 of which are subject to vesting over a three-year period from date of issuance.

The number of shareholders of record on April 10, 2006, was 112. However, we estimate that we have a significantly greater number of beneficial shareholders because a substantial number of our common shares are held of record by brokers or dealers for the benefit of their customers.

We have not paid a cash dividend on our common stock and currently intend to retain earnings to fund the growth and development of our business. Any future change in our policy will be made at the discretion of our board of directors in light of the financial condition, capital requirements, earnings prospects of Rosetta and any limitations imposed by lenders or investors, as well as other factors the board of directors may deem relevant.

We did not repurchase any of our securities during the fourth quarter of the year ended December 31, 2005.

Issuance and Sale of Capital Stock

During the year ended December 31, 2005, we sold the following securities that were not registered under the Securities Act of 1933, as amended:

 

Date of Sale

  

Title and Amount of

Securities Sold

  

Name or Class of Purchaser

of Securities

  

Consideration

July 7, 2005

   45,312,500—Common Stock    Qualified Institutional Buyers and Offshore Parties    $725 Million

July 13, 2005

   4,687,500—Common Stock    Qualified Institutional Buyers and Accredited Investors    $75 Million

Friedman, Billings & Ramsey Co, Inc. acted as underwriter and as placement agent in the foregoing sales of securities. For its role as underwriter and placement agent, FBR received a discount equal to seven percent (7%) of the aggregate consideration. All such sales were made in reliance upon an exemption from the registration provisions of the Securities Act set forth in Section 4(2) thereof relating to sales by an issuer not involving any public offering or the rules and regulations thereunder, under Rule 144A as promulgated under the Securities Act relating to resales to qualified institutional buyers, and under Regulation S as promulgated under the Securities Act relating to offshore transactions.

 

31


Table of Contents
Index to Financial Statements

Additionally, during the year ended December 31, 2005, we issued the following securities that were not registered under the Securities Act of 1933, as amended:

 

Date of Issuance

  

Title and Amount of

Securities Issued

  

Name or Class of Purchaser

of Securities

   Consideration

July 7, 2005

   231,400—Common Stock    Officers and Other employees    $ -0-

July 8, 2005

   253,500—Common Stock    Employees    $ -0-

July 13, 2005

   5,000—Common Stock    Employees    $ -0-

July 15, 2005

   1,000—Common Stock    Employees    $ -0-

July 25, 2005

   1,000—Common Stock    Employees    $ -0-

August 1, 2005

   21,500—Common Stock    Directors and Employees    $ -0-

August 3, 2005

   5,000—Common Stock    Employees    $ -0-

August 15, 2005

   12,500—Common Stock    Employees    $ -0-

August 22, 2005

   500—Common Stock    Employees    $ -0-

September 1, 2005

   2,500—Common Stock    Employees    $ -0-

September 6, 2005

   12,500—Common Stock    Employees    $ -0-

September 14, 2005

   5,000—Common Stock    Employees    $ -0-

September 19, 2005

   500—Common Stock    Employees    $ -0-

September 28, 2005

   8,500—Common Stock    Employees    $ -0-

October 21, 2005

   2,000—Common Stock    Employees    $ -0-

October 31, 2005

   10,000—Common Stock    Employees    $ -0-

November 1, 2005

   7,000—Common Stock    Employees    $ -0-

November 14, 2005

   6,000—Common Stock    Employees    $ -0-

November 21, 2005

   2,000—Common Stock    Employees    $ -0-

December 1, 2005

   4,500—Common Stock    Consultants and Employees    $ -0-

December 6, 2005

   1,000—Common Stock    Employees    $ -0-

December 12, 2005

   1,000—Common Stock    Employees    $ -0-

No underwriters were used in the foregoing issuances of securities. All such issuances were made in reliance upon an exemption from the registration provisions of the Securities Act set forth in Rule 701 as promulgated under the Securities Act relating to issuances of securities under compensatory plans.

Grants of Stock Options

Additionally, we have granted to our employees, including executive officers, options to purchase 706,550 shares of our common stock at exercise prices ranging from $16 per share to $19 per share. All such issuances were made in reliance on Rule 701 as promulgated under the Securities Act relating to issuances of securities under compensatory plans.

 

32


Table of Contents
Index to Financial Statements

Item 6. Selected Financial Data.

The following historical financial data, as of December 31, 2004, and for the fiscal years ended December 31, 2003 and 2004, and for the six months ended June 30, 2005, has been derived from the combined financial statements of the domestic oil and natural gas properties of Calpine (predecessor) appearing elsewhere, herein. The historical financial data as of December 31, 2003, and for the year ended December 31, 2002, has been derived from the combined financial statements of the domestic oil and natural gas properties of Calpine (predecessor) not appearing herein. The historical financial data as of December 31, 2001 and 2002, and for the year ended December 31, 2001, has been derived from the books and records of the domestic oil and natural gas properties of Calpine (predecessor). The historical financial data as of December 31, 2005 and for the six months ended December 31, 2005 (successor) has been derived from the consolidated financial statements of Rosetta Resources Inc. appearing herein. You should read the following selected historical consolidated/combined financial data in connection with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the audited consolidated/combined financial statements and related notes included elsewhere in this report. The predecessor historical financial data was derived from financial data of Calpine when we were not a stand-alone business. Additionally, the historical financial data reflects successful efforts accounting for oil and natural gas properties for the predecessor periods described above and the full cost method of accounting for oil and natural gas properties effective July 1, 2005 for the six months ended December 31, 2005, the successor period, described below and herein this report. In addition, the Company adopted the intrinsic value method of accounting for stock options as outlined in Accounting Practice Bulletin No. 25, “Stock Issued to Employees”, effective July 1, 2005. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The selected historical results are not necessarily indicative of results to be expected in future periods.

 

    Predecessor     Successor  
    For the Years Ended December 31,     For the Six
Months Ended
June 30,
    For the Six
Months Ended
December 31,
 
    2001   2002     2003     2004     2005     2005  
    (In thousands)        

Operating Results Data

           

Total revenue

  $ 190,665   $ 157,372     $ 279,916     $ 248,006     $ 103,831     $ 113,104  

Costs and expenses:

           

Depreciation, depletion and amortization

    52,590     64,109       72,766       81,590       30,679       40,500  

Impairment

    —       6,034       2,931       202,120       —         —    

Other costs and expenses

    41,974     57,971       74,391       67,359       36,289       37,001  
                                             

Total costs and expenses

    94,564     128,114       150,088       351,069       66,968       77,501  
                                             

Operating income (loss)

    96,101     29,258       129,828       (103,063 )     36,863       35,603  

Other income (expense)

    10,855     (26,821 )     (18,441 )     (24,298 )     (6,686 )     (6,531 )
                                             

Income (loss) before provision for income taxes, discontinued operations and cumulative effect of change in accounting principle, net of taxes

    106,956     2,437       111,387       (127,361 )     30,177       29,072  

Provision (benefit) for income taxes

    42,055     953       44,508       (48,525 )     11,496       11,537  
                                             

Income (loss) before discontinued operations and cumulative effect of change in accounting principle, net of taxes

    64,901     1,484       66,879       (78,836 )     18,681       17,535  

Discontinued operations, net of taxes

    2,183     (1,652 )     4,405       68,440       —         —    

Cumulative effect of change in accounting principle, net of taxes

    —       —         156       —         —         —    
                                             

Net income (loss)

  $ 67,084   $ (168 )   $ 71,440     $ (10,396 )   $ 18,681     $ 17,535  
                                             

 

33


Table of Contents
Index to Financial Statements

SELECTED HISTORICAL CONSOLIDATED/COMBINED FINANCIAL DATA (continued):

 

    Predecessor     Successor  
    For the Years Ended December 31,     For the Six
Months Ended
June 30,
    For the Six
Months Ended
December 31,
 
    2001     2002     2003     2004     2005     2005  
    (In thousands, except per share data)        

Earnings per share:

           

Basic

           

Income (loss) before discontinued operations and cumulative effect of change in accounting principle, net of taxes

  $ 1.30     $ 0.03     $ 1.34     $ (1.58 )   $ 0.37     $ 0.35  

Discontinued operations

  $ 0.04     $ (0.03 )   $ 0.09     $ 1.37     $ —       $ —    

Cumulative effect of change in accounting principle

  $ —       $ —       $ —       $ —       $ —       $ —    
                                               

Net income (loss)

  $ 1.34     $ (0.00 )   $ 1.43     $ (0.21 )   $ 0.37     $ 0.35  
                                               

Diluted

           

Income (loss) before discontinued operations and cumulative effect of change in accounting principle, net of taxes

  $ 1.30     $ 0.03     $ 1.33     $ (1.58 )   $ 0.37     $ 0.35  

Discontinued operations

  $ 0.04     $ (0.03 )   $ 0.09     $ 1.37     $ —       $ —    

Cumulative effect of change in accounting principle

  $ —       $ —       $ —       $ —       $ —       $ —    
                                               

Net income (loss)

  $ 1.34     $ (0.00 )   $ 1.42     $ (0.21 )   $ 0.37     $ 0.35  
                                               

Weighed average shares outstanding:

           

Basic

    50,000       50,000       50,000       50,000       50,000       50,003  

Diluted

    50,160       50,000       50,160       50,000       50,160       50,189  

Balance Sheet Data

           

Property and equipment, net(4)

  $ 830,092     $ 822,271     $ 830,390     $ 606,520     $ —       $ 935,936  

Assets of discontinued operations

  $ 99,160     $ 96,990     $ 111,254     $ —       $ —       $ —    

Total assets

  $ 975,199     $ 940,619     $ 990,893     $ 656,528     $       $ 1,119,269  

Long-term debt, less current maturities

  $ —       $ 684     $ 507     $ —       $ —       $ 240,000  

Owner’s Net Investment/Stockholders’ Equity

  $ 162,575     $ 162,407     $ 233,847     $ 223,451     $ —       $ 715,423  

Net cash provided by (used in) continuing operations:

           

Operating activities

  $ 185,935     $ 50,303     $ 152,407     $ 121,182     $ 59,379     $ 63,744  

Investing activities

  $ (666,795 )   $ (61,398 )   $ (62,132 )   $ (53,933 )   $ (30,645 )   $ (943,246 )

Financing activities

  $ 472,208     $ (5,145 )   $ (71,498 )   $ (71,646 )   $ (27,239 )   $ 979,226  

Other Financial Data (Unaudited)

           

Working capital (deficit)(1)

  $ (550,591 )   $ (537,828 )   $ (466,039 )   $ (240,508 )   $ —       $ 65,423  

Purchases of property and equipment(5)

  $ 684,537     $ 79,213     $ 102,700     $ 68,386     $ 32,202     $ 942,300  

 

34


Table of Contents
Index to Financial Statements

SELECTED HISTORICAL CONSOLIDATED/COMBINED FINANCIAL DATA (continued):

 

      Predecessor      Successor  
      For the Years Ended December 31,     For the Six
Months Ended
June 30,
     For the Six
Months Ended
December 31,
 
      2001     2002     2003     2004     2005      2005  
      (In thousands, except per share amounts)         

Reconciliation of Non-GAAP Financial Data(3)

             

EBITDA from continuing operations calculation is as follows:

             

Net income (loss)

   $ 67,084     $ (168 )   $ 71,440     $ (10,396 )   $ 18,681      $ 17,535  

Cumulative effect of change in accounting principle, net of taxes

     —         —         (156 )     —         —          —    

Income from discontinued operations, net of tax(2)

     (2,183 )     1,652       (4,405 )     (68,440 )     —          —    
                                                   

Income (loss) from continuing operations

     64,901       1,484       66,879       (78,836 )     18,681        17,535  

Interest (income) expense with affiliates, net

     (2,025 )     23,312       19,050       28,034       6,995        —    

Interest expense, net

                8,216  

Other interest (income) expense, net

     —         394       (62 )     (726 )     (516 )      (1,837 )

Income tax provision (benefit)

     42,055       953       44,508       (48,525 )     11,496        11,537  
                                                   

Income (loss) before interest and taxes

     104,931       26,143       130,375       (100,053 )     36,656        35,451  

Other (income) expense, net

     (8,830 )     3,115       (547 )     (3,010 )     207        152  
                                                   

Operating income

     96,101       29,258       129,828       (103,063 )     36,863        35,603  

Depreciation, depletion and amortization

     52,590       64,109       72,766       81,590       30,679        40,500  
                                                   

EBITDA from continuing operations

   $ 148,691     $ 93,367     $ 202,594     $ (21,473 )   $ 67,542      $ 76,103  
                                                   

(1) Working capital deficit includes $127 million, $444 million, $528 million and $492 million of notes payable to affiliates for the years ended December 31, 2004, 2003, 2002 and 2001 (predecessor), respectively.

 

(2) Represents the sale of the San Juan Basin New Mexico assets and the Piceance Basin Colorado assets in 2004.

 

(3) EBITDA from continuing operations is calculated as net income or loss excluding income taxes, cumulative effect of change in accounting principle, net interest expense, other income, depreciation, depletion and amortization, and income from discontinued operations. It does include an impairment charge of $202.1 million, $2.9 million and $6.0 million for the years ended December 31, 2004, 2003 and 2002 (predecessor) respectively. We believe that EBITDA from continuing operations is a financial indicator commonly used by analysts and is used by them as a basis for evaluating us with our peers. We use EBITDA from continuing operations as a performance measure such as a multiple for valuation purposes of our company and the oil and gas industry as a whole. EBITDA from continuing operations should not be considered in isolation or as a substitute for net income, operating income, and net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company’s profitability or liquidity.

 

(4) For the six months ended December 31, 2005 (successor), purchases of property and equipment include $910 million related to the acquisition of the oil and gas business of Calpine.

 

35


Table of Contents
Index to Financial Statements

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Rosetta Resources Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of natural gas and oil properties in the United States. We were formed as a Delaware corporation in June 2005. In July 2005, we acquired the oil and natural gas business of Calpine Corporation and affiliates. Our operations are concentrated in the Sacramento Basin of California, Lobo and Perdido trends in South Texas, and the U.S. Gulf of Mexico (both state and federal waters). In this section, we refer to Rosetta as “successor” and to the domestic oil and natural gas properties acquired from Calpine as “predecessor”.

In accounting for the oil and natural gas exploration and production business, the predecessor used the successful efforts method of accounting for oil and natural gas activities. However, in connection with our separation from Calpine, we have adopted the full cost method of accounting for our oil and natural gas properties, (see “Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting vs. Full Cost Method of Accounting” below for further discussion of the differential effects on the combined financial statements of the two accounting methods).

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production. Our future earnings will also be impacted by the changes in fair market value of hedges we executed to mitigate the volatility in the changes of oil and natural gas prices in future periods when such positions are settled as these instruments meet the criteria to be accounted for as cash flow hedges. Until settlement, the changes in fair market value of our hedges will be included as a component of stockholder’s equity to the extent effective. In periods of rising prices, these transactions will mitigate future earnings and in periods of declining prices will increase future earnings in the respective period the positions are settled.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce our reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. The permitting and approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups and has extended the time it takes us to receive permits. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Financial Highlights

The consolidated financial statements reflect total revenue of $113.1 million on total volumes of 13.5 Bcfe for the six months ended December 31, 2005 (successor). Operating income was $35.6 million or 31.5% of total revenue and included additional workover costs of approximately $2.0 million for our High Island A-442 and

 

36


Table of Contents
Index to Financial Statements

East Cameron 88 wells and $4.2 million of compensation expense for stock granted to employees. Additionally, operating income was affected by a decline in volumes and revenues resulting from Hurricanes Katrina and Rita and does not include volumes and revenues related to oil and natural gas properties not conveyed by Calpine in our acquisition, because consents had not been obtained at that time. Total net other expense (income) was interest expense on our credit facility offset by interest income on short term cash investments and interest capitalized to the full cost pool. Overall, our net income for the six months ended December 31, 2005 (successor) was $17.5 million or 15.5% of total revenue.

The combined financial statements reflect total revenue of $103.8 million on total volumes of 15.5 Bcfe for the six months ended June 30, 2005 (predecessor). Operating income was $36.9 million or 35.5% of total revenue and included work over cost and ad valorem taxes of $0.22 per Mcfe and $0.22 per Mcfe, respectively due to higher taxes in South Texas and a special reclamation tax in California as well as exploration costs of $2.4 million and dry hole expense of $2.0 million both of which are expensed as incurred based on the successful efforts method of accounting. Total net other expense was interest expense of $7.0 million on intercompany debt of $92.9 million offset by $(0.7) million of capitalized interest. Overall, net income for the six months ended June 30, 2005 (predecessor) was $18.7 million or 18% of total revenue.

Restatement of Financial Results for Third Quarter 2005

In connection with the preparation of our audited financial statements for the six-months ended December 31, 2005, we determined that certain costs of $1.1 million incurred in connection with our issuance of common stock in the third quarter 2005 were incorrectly accounted for as a reduction of the proceeds from such issuance in additional paid-in capital on our balance sheet and should initially have been accounted for as operating expenses on our income statement. In addition, we had over accrued certain costs of $0.1 million in additional paid-in capital. As a consequence, we have restated our financial results for the fiscal quarter ended September 30, 2005, as included in the Selected Data—Quarterly Information included herein, from what we previously disclosed in our registration statement on Form S-1 (333-128888), specifically in our Selected Financial Data, our Historical Unaudited Pro Forma Financial Data, and our unaudited consolidated financial statements as of September 30, 2005 and for the three months ended September 30, 2005.

The changes to correct the error are as follows:

 

    General and administrative costs are increased by $1.1 million;

 

    Net income for third quarter 2005 is reduced by $1.1 million to $8.2 million; and

 

    Earnings per share basic and diluted are reduced by $0.03 and $0.02 to $0.16 and $0.16 per share, respectively.

 

    Additional paid-in Capital is increased by $1.1 million to $748.6 million;

 

    Retained earnings are reduced by $1.1 million to $8.2 million.

See Selected Data—Quarterly Information for the restated financial data.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated/combined financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for

 

37


Table of Contents
Index to Financial Statements

making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments for our financial statements and those of our predecessor. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of the financial statements.

Oil and Natural Gas Reserves. Oil and natural gas reserve estimates impact many of the accounting estimates in the financial statements as further discussed below. The process of estimating quantities of oil and natural gas proved reserves, particularly proved undeveloped and proved developed non-producing reserves, is complex, requiring significant judgment and subjective decisions in the evaluation of all available geological, geophysical, engineering and economic data. Estimates of economically recoverable oil and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of governmental regulations, operating and workover costs, severance taxes and development costs, all of which may vary considerably from actual results. Accordingly, our reserve estimates are developed internally and subsequently, provided to a third party engineering firm which then generates an annual year-end reserve report. In addition, the data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates. The estimate of proved natural gas and oil reserves primarily impact property, plant and equipment amounts in the balance sheets and the depreciation, depletion and amortization amounts in the consolidated/combined statement of operations, among other items.

Successful Efforts Method of Accounting vs. Full Cost Method of Accounting. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in oil and natural gas exploration, development, and production. Two methods are prescribed: the successful efforts method and the full cost method of accounting for oil and natural gas properties. We have adopted the full cost method of accounting for oil and natural gas properties. Under the full cost method, all costs incurred in exploring for, acquiring, and developing oil and natural gas reserves are capitalized to a full cost pool, whether or not the activities to which they apply are successful. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and certain costs related to general corporate overhead or similar activities.

Under the successful efforts method that was used by our predecessor, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method whereas under the full cost method, gains or losses are generally included in the full cost pool unless the entire pool is sold. Under the full cost method, unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, these costs are transferred to the full cost pool and amortized. Under the successful efforts method, these costs are included in undeveloped leasehold cost or expensed depending on the nature of the expenditure. As a result, the financial statements for the six months ended December 31, 2005 will differ from companies that apply the successful efforts method and the financial statements presented herein for the six months ended June 30, 2005 and the years ended December 31, 2004 and 2003, since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and natural gas properties. A five percent positive or negative revision to proved reserves throughout the Company would decease or increase the depreciation, depletion and amortization rate by approximately $0.15 per Mmcfe to $0.23 per Mmcfe. This estimated impact is based on current data at December 31, 2005 and actual events could require different adjustments to depreciation, depletion and amortization.

 

38


Table of Contents
Index to Financial Statements

Under the full cost accounting method for oil and natural gas properties, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, inclusive of cash flow hedges, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings as a ceiling test write-down. This charge does not impact cash flow from operating activities, but would reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.

Under the successful efforts method of accounting for oil and natural gas properties followed by our predecessor, they reviewed their oil and natural gas properties periodically (at least annually) to determine if impairment of such properties was necessary. Property impairments occurred if a field discovered lower than anticipated reserves, reservoirs produced below original estimates or if commodity prices fell below a level that significantly affected anticipated future cash flows on the property. Proved oil and natural gas property values were reviewed when circumstances suggested the need for such a review and, if required, the proved properties were written down to their estimated fair market value based on proved reserves and other market factors. Unproved properties were reviewed quarterly to determine if there was an impairment of the carrying value, with any such impairment charged to expense in that current period.

Management assesses the undeveloped acreage, leasehold, geological and geophysical (seismic) costs and related capitalized interest to determine if any expenses should be impaired, reclassified to proved properties or classified as a dry hole and recorded as expense in the statement of operations. The predecessor recorded $202.1 million and $2.9 million in impairment charges related to reduced proved reserve projections based on the year end independent engineers report for the years ended December 31, 2004 and 2003, respectively.

Derivative Transactions and Hedging Activities. We enter into derivative transactions to hedge against changes in oil and natural gas prices from time to time primarily through the use of fixed price swap agreements, costless collars, and put options. Consistent with our hedge policy, and in connection with entering into our credit facilities, we entered into a series of natural gas fixed-price swaps for a significant portion of our expected natural gas production through 2009. In December 2005, we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for approximately 10,000 MMBtu per day (see “Quantitative and Qualitative Disclosure About Market Risk”). These transactions are recorded in our financial statements in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Although not risk free, we believe this policy will reduce our exposure to commodity price fluctuations and thereby achieve a more predictable cash flow. We do not enter into derivative agreements for trading or other speculative purposes.

In accordance with SFAS No. 133, as amended, all derivative instruments are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair market value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions every three months, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair market value of the ineffective portion of cash flow hedges are included in other income (expense).

 

39


Table of Contents
Index to Financial Statements

Asset Retirement Obligations. Our predecessor adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” as of January 1, 2003. SFAS No. 143 required them to record the fair market value of a liability for an asset retirement obligation (“ARO”), net of salvage value, in the period in which it was incurred. Upon adoption of SFAS No. 143, a liability was recorded for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost (“ARC”) was capitalized as part of the carrying value of the associated asset and a cumulative effect of a change in accounting principle was recorded in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. Subsequent to adoption, liabilities were required to be accreted to their present value each period and capitalized costs were depreciated over the estimated useful life of the related assets. This periodic accretion expense is recorded as depreciation, depletion and amortization in the consolidated/combined statement of operations. Upon settlement of the liability, the obligation is settled against its recorded amount and the resulting gain or loss is recorded in the financial statements.

Income Taxes. Under SFAS No. 109, “Accounting for Income Taxes,” deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse.

Income taxes have been calculated for the Company based on the appropriate tax regulations since it will file a tax return for the six months ended December 31, 2005 and as if the domestic oil and natural gas business of Calpine had filed a separate return for the six months ended June 30, 2005 and the years ended December 31, 2004 and 2003. See additional information in Note 10. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

To arrive at the income tax provision and other tax balances, significant judgment is required. In the ordinary course of business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions and multi-state taxation of operations. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our tax provisions and accruals. Such differences could have a material impact on our income tax provision, other tax accounts and net income in the period in which such determination is made. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance, there is no assurance that a valuation allowance might be needed in the future to provide for additional deferred tax assets that may not be realizable. Should we determine the need for a valuation allowance it could have a material adverse impact on our income tax provision and results of operations in the period in which such determination is made.

The effective income tax rates for continuing operations were 38.1%, and 40.0% in fiscal year 2004 and 2003, 38.1% for the six months ended June 30, 2005 and 39.7% for the six months ended December 31, 2005, respectively. The effective tax rate in all periods is the result of taxes on earnings in various domestic tax jurisdictions that apply a broad range of state income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes, tax credits and other permanent differences. Future effective tax rates could be adversely affected if earnings are lower than anticipated, if unfavorable changes in tax laws and regulations occur, or if we experience future adverse determinations by taxing authorities after any related litigation.

Stock-based Compensation. On January 1, 2003, Calpine prospectively adopted, and the combined financial statements for 2003 and 2004 and the six months ended June 30, 2005 are presented, the fair market value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (SFAS No. 123”). Expense amounts included in the combined historical financial statements for the years ended December 31, 2004 and 2003 and the six months ended June 30, 2005 are based

 

40


Table of Contents
Index to Financial Statements

on stock based compensation granted to employees by Calpine. Stock options were granted at an option price equal to the quoted market price at the date of the grant or award.

In determining our accounting policies, we have chosen to apply the intrinsic value method pursuant to Accounting Standards Board (“APB”) APB No. 25, “Stock Issued to Employees” (“APB No. 25”) effective July 2005. Under APB No. 25, no compensation is recognized when the exercise price for options granted equal the fair value of the Company’s common stock on the date of the grant.

New Accounting Pronouncements Not Yet Adopted

SFAS No. 123-R. In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123-R. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) and supersedes APB No. 25, and its related implementation guidance. This statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the fair market value of the award on the date of grant (with limited exceptions), which must be recognized over the period during which an employee is required to provide service in exchange for the award—the requisite service period (usually the vesting period). The statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options, or other equity instruments or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity’s shares or other equity instruments or (b) that require or may require settlement by issuing the entity’s equity shares or other equity instruments. The statement requires the accounting for any excess tax benefits to be consistent with the existing guidance under SFAS No. 123, which provides a two-transaction model summarized as follows:

 

    If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution to paid-in-capital.

 

    If the compensation cost exceeds the actual tax deduction, the write-off of the unrealized excess tax benefits would first reduce any available paid-in capital arising from prior excess tax benefits, and any remaining amount would be charged against the tax provision in the income statement.

The statement also amends SFAS No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow. However, the statement does not change the accounting guidance for share-based payment transactions with parties other than employees provided in SFAS No. 123 as originally issued and EITF Issue No. 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services”. Further, this statement does not address the accounting for employee share ownership plans, which are subject to AICPA Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans”.

The statement applies to all awards granted, modified, repurchased, or cancelled after January 1, 2006, and to the unvested portion of all awards granted prior to that date. Public entities that used the fair market value method for either recognition or disclosure under SFAS No. 123 may adopt this Statement using a modified version of prospective application (modified prospective application). Under modified prospective application, compensation cost for the portion of awards for which the employee’s requisite service has not been rendered that are outstanding as of January 1, 2006 must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of awards shall be based on the original fair market value of those awards on the date of grant as calculated for recognition under SFAS No. 123. The compensation cost for those earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS No. 123. Furthermore, the method of recognizing forfeitures must now be based on an estimated forfeiture rate and can no longer be based on forfeitures as they occur.

The adoption of SFAS No. 123-R is not expected to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

 

41


Table of Contents
Index to Financial Statements

Accounting Changes and Error Corrections. In May 2005 the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154”), which changes the requirements for the accounting for and the reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed.

APB 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is practicable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the balance sheet for that period rather than being reported in the statement of operations. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable.

SFAS 154 defines retrospective application as the application of a different accounting principle to prior accounting periods as if that principle had always been used or as the adjustment of previously issued financial statements to reflect a change in the reporting entity. SFAS 154 also redefines restatement as the revising of previously issued financial statements to reflect the correction of an error.

SFAS 154 requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle, such as a change in nondiscretionary profit-sharing payments resulting from an accounting change, should be recognized in the period of the accounting change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 carries forward without change the guidance contained APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. This Statement also carries forward the guidance in APB 20 requiring justification of a change in accounting principle on the basis of preferability.

SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted for accounting changes and corrections of errors made in fiscal years beginning after the date this Statement is issued. SFAS 154 does not change the transition provision of any existing accounting pronouncements, including those that are in a transition phase as of the effective date. The adoption of this statement is not expected to impact the Company’s consolidated financial position or results of operations.

Exchanges of Nonmonetary Assets. In January 2005, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No 29. This statement, which addresses the measurement of exchanges of nonmonetary assets, is effective prospectively for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of this statement did not impact the Company’s consolidated financial position or results of operations.

Accounting for Certain Hybrid Financial Instruments. In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Instruments-an amendment of FASB Statements 133 and 140, which is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after

 

42


Table of Contents
Index to Financial Statements

September 15, 2006. The statement improves financial reporting by eliminating the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. The Statement also improves financial reporting by allowing a preparer to elect fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to bifurcated, if the holder elects to account for the whole instrument on a fair value basis. The Company is currently evaluating the impact, if any, of this Statement on the financial statements.

Results of Operations

In July 2005, we acquired the oil and natural gas business of Calpine Corporation and affiliates. Due to the acquisition, the results of operations for the year ended December 31, 2005 are presented in two periods, successor comprising the six months ended December 31, 2005 and predecessor comprising the six months ended June 30, 2005. In addition, differences in accounting principles of the predecessor and successor exist, primarily related to the full cost method of accounting for oil and natural gas properties adopted by us and the successful effort method of accounting for oil and natural gas properties followed by the predecessor. In addition, the predecessor adopted on January 1, 2003, SFAS No. 123, “Accounting for Stock-Based Compensation” to measure the cost of employee services received in exchange for an award of equity instruments, whereas we adopted the intrinsic value method of accounting for stock options and stock awards effective July 1, 2005.

Successor

Six Months Ended December 31, 2005

 

     Six Months Ended
December 31, 2005
 
     (In thousands)  

Total revenue

   $ 113,104  
        

Lease operating expense

     15,674  

Depreciation, depletion and amortization

     40,500  

Treating and transportation

     1,286  

Marketing fees

     1,379  

Production taxes

     3,975  

General and administrative costs

     14,687  

Interest expense, net of interest capitalized

     8,216  

Interest income

     (1,837 )

Other (income) expense, nets

     152  

Provision (benefit) for income taxes

     11,537  
        

Net Income

   $ 17,535  
        

Production:

  

Gas (Bcf)

     12.4  

Oil (Mbbl)

     185.6  

Total Equivalents (Bcfe)

     13.5  

$ per unit:

  

Avg. gas price per Mmcf

   $ 8.23  

Avg. gas price per Mmcf excluding hedging

     9.57  

Avg. oil price per Mbbl

     59.52  

Avg. revenue per Mmcfe

     8.38  

Avg. operating expense per Mmcfe

     1.16  

Avg. transportation & marketing per Mmcfe

     0.20  

Avg. production tax expense per Mmcfe

     0.29  

Avg. G&A per Mmcfe

     1.09  

Avg. DD&A per Mmcfe (excluding ceiling test write-downs)

   $ 3.00  

 

43


Table of Contents
Index to Financial Statements

Total Revenue. Total revenue of $113.1 million for the six months ended December 31, 2005 consists primarily of natural gas sales comprising 90.3% of total revenue on total volumes of 13.5 Bcfe. Natural gas sales revenue was $102.1 million, including the effects of hedging, based on total gas production volumes of 12.4 Bcf. Lobo and Perdido production was 3.9 Bcf and 1.5 Bcf or 28.9% and 11.2%, respectively, or a total of 5.4 Bcf and 40.1% of total volumes. California production was 5.3 Bcf or 39.0% of total volumes at a total average price of $9.08 per Mcfe, excluding the effects of hedging. California production is down due to the delay in our drilling program pending an additional rig contracted in the first quarter of 2006 and compression issues. The effect of hedging on natural gas sales revenue was a decrease of $16.6 million related to volumes of 8.0 MMbtu for a decrease in total price to $8.23 per Mcf.

Oil revenue was $11.0 million based on oil production volumes of 185.6 MBbls. Southern region production was 21.9 MBbls, 8.5 MBbls, 8.3 MBbls, 42.0 MBbls and 93.0 MBbls from Lobo, Perdido, State Waters, Other Onshore and Gulf of Mexico or 94% of oil production for the six months ended December 31, 2005 at a total average price of $59.61 per Bbl for these fields. Overall volumes are down in the Gulf of Mexico due to Hurricanes Katrina and Rita and a workover program at High Island and East Cameron that was delayed in prior years due to capital constraints imposed by Calpine and does not include volumes and revenues related to oil and natural gas properties not conveyed by Calpine in our acquisition, because consents had not been obtained at that time. Fluctuations in product prices significantly impacted our revenue from existing properties

Lease Operating Expense. Our lease operating expense of $15.7 million is primarily due to oil and natural gas volumes which totaled 13.5 Bcfe for the six months ended December 31, 2005 or costs of $1.12 per Mcfe. The costs included workover costs on our High Island A-442 and East Cameron 88 wells in the Gulf of Mexico and the La Perla field in South Texas. The costs included workover costs, ad valorem taxes and insurance of $0.22 per Mcfe, $0.25 per Mcfe and $0.04 per Mcfe, respectively.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense was $40.5 million for the six months ended December 31, 2005. We adopted the full cost method of accounting for oil and gas properties as further discussed in our “Critical Accounting Policies and Estimates” above. whereby related costs are capitalized into the full cost pool. Our depletion rate for this period was an average of $3.00 per MMcfe. There were no ceiling test write-downs for the six months ended December 31, 2005.

Treating and Transportation. Treating and transportation was $1.3 million for the six months ended December 31, 2005 related to the treating and transportation related to a portion of our total natural gas production volumes of 12.4 Bcf.

Marketing Fees. Marketing fees were $1.4 million for the six months ended December 31, 2005. These fees relate to the contract rate charged by Calpine Producer Services (“CPS”) to market our gas. The fee payable by us under the agreement is based on net proceeds of all commodity sales for volumes covered by the agreement at a rate of 0.75%. This rate decreases as the volumes marketed increases.

Production Taxes. Production taxes as a percentage of natural gas and oil sales are approximately 3.56% for the six months ended December 31, 2005. Production taxes are primarily based on the wellhead values of production and vary across the different regions.

General and Administrative Costs. General and administrative costs of $14.7 million is net of capitalization of general and administrative costs of $3.5 million as a component of our oil and natural gas properties under the full cost method of accounting for oil and natural gas properties which we adopted July 1, 2005. General and administrative costs for this period include $4.2 million of stock compensation expense for stock granted to employees during the period and $10.9 million of salary and employee benefit costs before capitalization of any of these costs to our oil and natural gas properties.

Interest (income) expense. Interest (income) expense of $8.2 million, including amortization of deferred loan fees of $0.6 million related to interest on our senior credit facility and term loan which is described in

 

44


Table of Contents
Index to Financial Statements

“Liquidity and Capital Resources” and notes to the consolidated/combined financial statements for the six months ended December 31, 2005. Interest income of $1.8 million was earned on available cash invested in short term money market investments.

Other (Income) Expense. Other (income) expense of $0.2 million relates primarily to investment income from an equity interest for the six months ended December 31, 2005 of $0.2 million.

Provision for Income Taxes. The effective tax rate for the six months ended December 31, 2005 was 39.7%. The provision for income taxes differs from the taxes computed at the federal statutory income tax rate due primarily to state taxes.

Net Income. We had total revenue of $113.1 million on total volumes of 13.5 Bcfe for the six months ended December 31, 2005. Operating income was $35.6 million or 31.5% of total revenue and included additional workover costs of approximately $2.0 million for our High Island A-442 and East Cameron 88 wells and $4.2 million of compensation expense for stock granted to employees. Additionally, operating income was affected by a decline in volumes and revenues resulting from Hurricanes Katrina and Rita and does not include volumes and revenues related to oil and natural gas properties not conveyed by Calpine in our acquisition, because consents had not been obtained at that time. Total net other expense (income) was interest expense on our credit facility offset by interest income on short term money market investments. Overall, our net income was $17.5 million or 15.5% of total revenue.

Predecessor

Six Months Ended June 30, 2005

 

     Six Months Ended
June 30, 2005
 
     (In thousands)  

Total revenue

   $ 103,831  
        

Lease operating expense

     16,629  

Depreciation, depletion and amortization

     30,679  

Exploration expense

     2,355  

Dry Hole costs

     1,962  

Treating and transportation

     1,998  

Marketing fees

     913  

Production taxes

     2,755  

General and administrative costs

     9,677  

Interest expense with affiliates, net of interest capitalized

     6,995  

Interest income

     (516 )

Other (income) expense, net

     207  

Provision (benefit) for income taxes

     11,496  
        

Net Income

   $ 18,681  
        

Production:

  

Gas (Bcf)

     14.5  

Oil (Mbbl)

     164.0  

Total Equivalents (Bcfe)

     15.5  

$ per unit:

  

Avg. gas price per Mmcf

   $ 6.59  

Avg. oil price per Mbbl

     49.86  

Avg. revenue per Mmcfe

     6.70  

Avg. operating expense per Mmcfe

     1.08  

Avg. transportation & marketing per Mmcfe

     0.19  

Avg. production tax expense per Mmcfe

     0.18  

Avg. G&A per Mmcfe

     0.63  

Avg. DD&A per Mmcfe (excluding impairments)

   $ 1.98  

 

45


Table of Contents
Index to Financial Statements

Total Revenue. Total revenue of $103.8 million for the six months ended June 30, 2005 consisted primarily of natural gas sales of $95.6 million or 92.1% of total revenue. Oil revenue was $8.1 million with oil production volumes of 164 MBbls primarily from the Gulf of Mexico region which produced 72.7 MBbls or 44% of oil production for the six months ended June 30, 2005 at an average price of $49.86 per Bbl. Natural gas sales revenue was $95.6 million with gas production volumes of 14.5 MMcf primarily from Sacramento Basin with 6.5 MMcf or 44.8% of total volumes and South Texas, primarily from Lobo of 3.7 MMcf and Perdido 1.8 MMcf, or 5.5 MMcf or 37.9% of total volumes at an average price of $6.59 per Mcf. Overall volumes were down due to capital constraints of our predecessor.

Lease Operating Expense. Lease operating expense of $16.6 million related directly to oil and natural gas volumes which totaled 15.5 MMcfe for the six months ended June 30, 2005 or costs of $1.08 per Mcf. The costs included workover cost, ad valorem taxes and insurance of $0.22 per Mcfe, $0.22 per Mcfe and $0.06 per Mcfe, respectively due to higher taxes in South Texas and a special reclamation tax in California.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense was $30.7 million for the six months ended June 30, 2005 under the successful efforts method of accounting for oil and natural gas properties. Our depletion rate for this period was an average of $1.97 per MMcfe.

Exploration expense. Exploration expense was $2.3 million for the six months ended June 30, 2005 under the successful efforts method of accounting for oil and natural gas properties. This expense was comprised of geological and geophysical salaries and expenses of $1.7 million and delay rentals and seismic costs of $0.6 million related primarily to expenditures in Texas State Waters of $0.3 million, $0.1 million in the Lobo Trend and $0.1 million in the Rio Vista field.

Dry hole costs. Dry hole costs were $2.0 million as a result of four exploratory dry holes for the six months ended June 30, 2005 under the successful efforts method of accounting for oil and natural gas properties.

Treating and Transportation. Treating and transportation was $2.0 million for the six months ended June 30, 2005 related to the treating and transportation related to our total natural gas production volumes of 14.5 Bcf.

Production Taxes. Production taxes as a percentage of natural gas and oil sales are approximately 2.7% for the six months ended June 30, 2005. Production taxes were primarily based on the wellhead values of production and vary across the different regions.

General and Administrative Costs. General and administrative costs of $9.7 million is net of capitalization of general and administrative costs of $3.6 million as a component of our oil and natural gas properties. Of the $9.7 million in total general and administrative costs, $5.9 million relates to salary and employee benefits and $1.3 million and $1.7 million relates to legal costs and merger and acquisition costs, respectively, associated with the sale of the oil and natural gas business to the Company.

Interest (income) expense. Interest (income) expense was $7.0 million related to intercompany debt with Calpine Corporation of $92.9 million offset by capitalized interest of $(0.7) million.

Other (Income) Expense. Other (income) expense of $0.2 million relates to investment income from an equity interest for the six months ended June 30, 2005.

Provision (Benefit) for Income Taxes. The effective tax rate for the six months ended June 30, 2005 was 38.1%. The provision for income taxes differs from the taxes computed at the federal statutory income tax rate due primarily to state taxes.

Net Income. Our predecessor, had total revenue of $103.8 million on total volumes of 15.5 Bcfe for the six months ended June 30, 2005. Operating income was $36.9 million or 35.5% of total revenue and included work

 

46


Table of Contents
Index to Financial Statements

over cost and ad valorem taxes of $0.22 per Mcfe and $0.22 per Mcfe, respectively due to higher taxes in South Texas and a special reclamation tax in California, as well as, exploration expense of $2.4 million and exploratory dry hole expense of $2.0 million, both of which were expensed as incurred based on the successful efforts method of accounting. Total net other expense was interest expense of $7.0 million on intercompany debt of $92.9 million offset by capitalized interest of $(0.7) million. Overall, the net income was $18.7 million or 18% of total revenue.

Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003

Predecessor

 

     Year Ended
December 31,
2004
    Year Ended
December 31,
2003
    Net
Change
    Net
Change
 
(In thousands)                         
                 Increase
(Decrease)
    % Increase
(Decrease)
 

Total revenue

   $ 248,006     $ 279,916     $ (31,910 )   -11.4 %
                    

Lease operating expense

     30,785       29,586       1,199     4.1 %

Depreciation, depletion and amortization

     81,590       72,766       8,824     12.1 %

Exploration expense

     5,352       4,105       1,247     30.4 %

Dry Hole costs

     2,088       12,624       (10,536 )   -83.5 %

Impairment

     202,120       2,931       199,189     6795.9 %

Treating and transportation

     3,509       4,759       (1,250 )   -26.3 %

Affiliated Marketing fees

     1,887       2,856       (969 )   -33.9 %

Production taxes

     4,322       3,725       597     16.0 %

General and administrative costs

     19,416       16,736       2,680     16.0 %

Interest expense with affiliates, net of amount capitalized

     28,034       19,050       8,984     47.2 %

Interest income

     (726 )     (62 )     (664 )   1071.0 %

Other (income) expense, net

     (3,010 )     (547 )     (2,463 )   450.3 %

Provision (benefit) for income taxes

     (48,525 )     44,508       (93,033 )   -209.0 %

Discontinued operations, net of taxes

     68,440       4,405       64,035     1453.7 %

Cumulative effect of change in accounting principle, net of taxes

     —         156       (156 )   -100.0 %
        

Net Income (Loss)

   $ (10,396 )   $ 71,440     $ (81,836 )   -114.6 %
        

Production:

        

Gas (Bcf)

     37.3       49.6       (12.3 )   (24.8 )%

Oil (Mbbl)

     600.0       434.0       166.0     38.2 %

Total Equivalents (Bcfe)

     40.9       52.2       (11.3 )   (21.6 )%

$ per unit:

        

Avg. Gas Price per Mmcfe

   $ 6.02     $ 5.38     $ 0.64     11.9 %

Avg. Oil Price per Mbbl

     39.08       29.67       9.41     31.7 %

Avg. Equivalents per Mmcfe

     6.06       5.36       0.70     13.1 %

Avg. operating expense per Mmcfe

     0.75       0.57       0.18     31.6 %

Avg. transportation & marketing per Mmcfe

     0.13       0.15       (0.02 )   -13.3 %

Avg. production tax expense per Mmcfe

     0.11       0.07       0.04     57.1 %

Avg. G&A per Mmcfe

     0.48       0.32       0.16     50.0 %

Avg. DD&A per Mmcfe (excluding impairments)

   $ 2.00     $ 1.39     $ 0.61     43.9 %

Total Revenue. Production revenue decreased by $31.9 million or 11.4% for the year ended December 31, 2004 as compared to the year ended December 31, 2003. Oil revenues increased by $13.0 million or 125% over 2003 due to an increase in average realized oil prices from $29.70/barrel in 2003 to $39.05/barrel in 2004 as well as an increase in production volume from 434 MBbls in 2003 to 600 MBbls in 2004. The increase in volume was

 

47


Table of Contents
Index to Financial Statements

primarily due to increased production offshore in the Gulf of Mexico in 2004. Natural gas sales revenue decreased by $45.0 million or 16.7%, in 2004 compared to 2003 primarily due to a decrease in production volumes from 2003 to 2004 by approximately 12.3 MMcf. This decrease was partially offset by an increase in natural gas prices of $0.64 per Mcf. The overall decrease in production volume was primarily due to the capital constraints of our predecessor, and its impact on our ability to further our exploration and development program to offset depleted producing wells as well as the decreased consumption of our product by our predecessor. Also, significant fluctuations in product prices significantly impact our revenue from existing properties. See “Quantitative and Qualitative Disclosure about Market Risk”.

Lease Operating Expense. Our predecessor’s lease operating expense increased approximately $1.2 million in 2004 from $29.6 million in 2003 to $30.8 million in 2004. The $1.2 million increase is primarily due to drilling activity in the Impac field in South Texas operated by EOG Resources, Inc., which resulted in an increase in non-operated lease operating expense. Slight increases in salt water disposal costs (primarily in California), supervisory and labor costs and ad valorem taxes were offset by slight decreases in well insurance costs, outside consulting fees and well servicing costs. Therefore, a decrease in production did not significantly reduce these types of costs. In addition, we will not develop our acreage in Kansas and Missouri and will let the relevant leases expire in accordance with their terms. These leases do not meet our minimum economic guidelines and their lease costs were insignificant.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) was $81.6 million in 2004 compared to $72.8 million in 2003 mainly due to the addition of 20 new wells in the Impac field in South Texas during 2004. Under successful efforts accounting, depletion expense is separately computed for each field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each field to determine a depletion rate for current production. The DD&A rate in South Texas went from approximately $2.60 per Mcfe in 2003 to approximately $3.50 per Mcf in 2004 as the costs associated with drilling these wells increased significantly relative to the reserves added during the period.

Exploration Expense. Exploration costs increased $1.3 million to $5.4 million in 2004 as our predecessor had slightly more exploration activity in 2004 over 2003. In addition, the costs of exploration increased in 2004.

Dry Hole Costs. Dry hole costs were $2.1 million in 2004 compared to $12.6 million in 2003. Our predecessor had eight dry holes in 2003 compared to four in 2004 and correspondingly, the costs of each of the dry holes in 2003 were higher than 2004.

Proved Property Impairment. During 2004, our predecessor revised downward its estimate of proved reserves by a total of approximately 58 Bcfe, or 12% as of December 31, 2004. Approximately 69% of the total revision was attributable to the downward revision of the estimate of proved reserves in the South Texas fields and to a smaller extent unanticipated well performance decline in offshore fields. The remaining 31% of the total revision was primarily due to the downward revision of our predecessor’s estimate of proved reserves in California of 17%, Other Onshore of 10% and Gulf of Mexico of 4%. The downward revisions of our predecessor’s estimates were based on the independent reservoir engineer’s year-end reserve report, which reflected production results and drilling activity that occurred during 2004 and used historical field level decline curves. Due to significant capital constraints by our predecessor, drilling activity was minimized and correspondingly the estimate of proved reserves could not be supported through drilling success or future capital activity and the downward revision was required. In addition, under the successful efforts method of accounting for oil and natural gas properties, individual assets are grouped at the lowest level for which there are identifiable cash flows. With minimal drilling activity and the evaluation of cash flows at this level, proved reserves for South Texas and California fields and the Gulf of Mexico had to be revised downward at each individual field level. As a result of the decreases, primarily in proved undeveloped reserves, a non-cash impairment charge of approximately $202.1 million was recorded for the year ended December 31, 2004. For the year ended December 31, 2003, the impairment charge recorded was $2.9 million related to the downward revision of the estimate of proved reserves in certain fields primarily in Mississippi and Louisiana.

 

48


Table of Contents
Index to Financial Statements

Treating and Transportation. Treating and transportation decreased $1.3 million or 26.3% from $4.8 million in 2003 to $3.5 million for 2004. This decrease is primarily as a result of a decrease in production volumes in 2004 as compared to 2003.

Affiliated Marketing Fees. Affiliated marketing fees decreased $1.0 million or 34.5% to $1.9 million 2004. This is primarily due to a decrease in the contract rate from 0.75% to 0.62% charged by Calpine Producer Services.

Production Taxes. Production taxes as a percentage of natural gas and oil sales were 1.7% in 2004 and 1.3% in 2003. Production taxes are primarily based on the wellhead values of production and vary across the different regions. Production taxes increased as a result of accrued severance taxes in 2004 related to our increased drilling activity in our south Texas properties.

General and Administrative Costs. General and administrative costs increased $2.7 million from $16.7 million in 2003 to $19.4 million in 2004. The increase is primarily due to higher wages and bonuses in 2004. Corporate overhead allocation contributed to the increase as well, resulting from higher costs for facilities and rent due to the move of our corporate offices in February 2004. General and administrative costs include stock-based compensation granted to our employees by the predecessor. On January 1, 2003, the predecessor adopted the fair market value method of accounting for stock-based compensation pursuant to SFAS No. 123. Stock compensation expense of $0.8 million and $0.1 million was recorded in 2004 and 2003, respectively.

Interest Expense with Affiliates. Interest expense with affiliates increased as a result of increased interest rates related to average affiliated debt balances and as result of lower capitalization of interest expense in 2004 when compared to 2003. Interest rates on affiliated party debt ranged from 8.75% to 9.05% in 2004 compared to 2003 in which the rate was 8.75% for the entire year. Capitalized interest was $20.2 million in 2003 compared with $0.7 million in 2004. Properties classified as undeveloped in 2003 were developed and classified as proved properties in 2004, capitalized interest decreased from year to year thus resulting in the decrease in capitalized interest.

Other (Income) Expense. In 2003, other (income) expense of $0.6 million consisted of a $1.1 million gain on sale of certain Oklahoma properties to Loto Energy, LLC offset by $0.5 million project development expense relating to a canceled business opportunity in Europe. The increase in 2004 of $2.4 million was primarily due to the gains on sales of the Sargent South field and certain Oklahoma properties to BV Production I, L.P.

Provision (Benefit) for Income Taxes. For 2004 and 2003, the effective rate was 38.1% and 40.0%, respectively. The effective tax rate in all periods is the result of the earnings in various domestic tax jurisdictions that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to state taxes. Future effective tax rates could be adversely affected if earnings are lower than anticipated, if unfavorable changes in tax laws and regulations occur, or if the Company experiences future adverse determinations by taxing authorities after any related litigation.

Gain on Discontinued Operations, Net of Tax. In September 2004, we completed the sale of our Rocky Mountain natural gas properties that were primarily concentrated in the two geographic areas of the Colorado Piceance Basin and the New Mexico San Juan Basin. As a result of the sale, the predecessor recorded income from discontinued operations, net of tax of $68.4 million, including a pre-tax gain of approximately $103.7 million.

Cumulative Effect of Change in Accounting Principle. The predecessor adopted Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), as of January 1, 2003. SFAS No. 143 requires us to record the fair market value of a liability for an asset retirement obligation (“ARO”), net of salvage value, in the period in which it is incurred. Upon adoption of SFAS No. 143, the predecessor recorded a liability for the present value of all legal obligations associated with the retirement of

 

49


Table of Contents
Index to Financial Statements

tangible long-lived assets and an asset retirement cost (“ARC”) was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS No. 143, a cumulative effect of a change in accounting principle of $0.1 million was also recorded in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost.

Net Income. In addition to fluctuations in oil and natural gas production and sales prices, our net income can vary significantly from period to period because of events or circumstances which trigger recognition of expenses for unsuccessful wells or impairments of properties. Further, we calculate certain expenses, such as depletion and depreciation, using estimates of oil and natural gas reserves that can vary significantly.

The net loss in 2004 was primarily due to the impairment charge of $202.1 million recorded in the fourth quarter of 2004. The evaluation performed by the predecessor indicated that certain fields in South Texas and Gulf of Mexico had net book values in excess of the undiscounted future net cash flows associated with their proved NYMEX oil and natural gas property reserve estimates, thus requiring that the net book values of those properties be written down to fair market value based on discounted cash flows. Since the proved property impairment is determined by the predecessor on a field-by-field basis, the impairment charge may vary significantly between years based on each year’s results.

The effect of the non-cash impairment charge was partially offset by a tax benefit and the gain on sale of discontinued operations. The gain on sale of discontinued operations was a result of the sale of our natural gas properties in the New Mexico San Juan Basin and Colorado Piceance Basin. Net income was also impacted by an increase in affiliated interest expense due to the increase in the inter-company borrowing rate in the fourth quarter of 2004.

Liquidity and Capital Resources

Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We will actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of our production thereby mitigating our exposure to price declines, but will also limit our earnings potential in periods of rising natural gas prices. This derivative transaction activity will allow us the flexibility to continue to execute our capital plan if prices decline during the period our derivative transactions are in place. In addition, the majority of our capital expenditures will be discretionary and could be curtailed if our cash flows declined from expected levels. In connection with entering into our credit facilities, we entered into a series of natural gas fixed-price swaps for a significant portion of our expected production through 2009. Consistent with our hedge policy, in December 2005, we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for approximately 10,000 MMBtu per day which represents approximately 10% of our 2006 natural gas production based on the Netherland Sewell reserve report at December 31, 2005. Additionally, we may enter into other agreements including fixed-price, forward price, physical purchase and sales contracts, futures, financial swaps, option contracts and put options.

Senior Secured Revolving Line of Credit. BNP Paribas, in July 2005 provided us with a senior secured revolving line of credit concurrent with the acquisition in the amount of up to $400 million. This revolving line of credit was syndicated to a group of lenders on September 27, 2005. Availability under the revolver is restricted to the borrowing base, which initially was $275 million and was reset to $325 million, upon amendment, as a result of the hedges put in place in July 2005 and the favorable effects of the exercise of the over-allotment option we granted through which we received $70 million of funds (net of transaction fees). In July 2005, we repaid $60 million of the $225 million in original borrowings on the Revolver. The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements. Amounts outstanding under the revolver bear interest, as amended, at specified margins over the London Interbank Offered Rate (LIBOR) of 1.25% to 2.00%. Such margins will fluctuate based on the

 

50


Table of Contents
Index to Financial Statements

utilization of the facility. Borrowings under the Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the PV-10 reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of the stock of domestic subsidiaries, and a lien on cash securing the Calpine gas purchase and sale contracts. These collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants of a minimum current ratio of not less than 1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At December 31, 2005, our current ratio was 4.6 to 1.0 and our leverage ratio was 1.5 to 1.0. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance

with all covenants at December 31, 2005. All amounts drawn under the revolver are due and payable on July 7, 2009. Availability under the revolving line of credit was $160 million at December 31, 2005.

Second Lien Term Loan. BNP Paribas, in July 2005, also provided us with a second lien term loan concurrent with the acquisition, in the amount of $100 million. On September 27, 2005, we repaid $25 million of borrowings on the Term Loan, reducing the balance to $75 million and syndicated such loan to a group of lenders including BNP Paribas. Borrowings under the term loan initially bore interest at LIBOR plus 5.00%. As a result of the hedges put in place in July 2005 and the favorable effects of our private equity placement, as described above, the interest rate for the second lien term loan has been reduced to LIBOR plus 4.00%. The loan is collateralized by second priority liens on substantially all of our assets. We are subject to the financial covenants of a minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly with the pro forma effect of acquisitions and divestitures. At December 31, 2005, our asset coverage ratio was 2.2 to 1.0 and our leverage ratio was 1.5 to 1.0. In addition, we will be subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at December 31, 2005. The revised principal balance is due and payable on July 7, 2010.

Cash Flows

 

     Successor     Predecessor  
    

Six Months Ended

December 31,

2005

   

Six Months Ended

June 30,

2005

    Year Ended
December 31,
 
         2004     2003  
     (In thousands)  

Cash flows provided by operating activities

   $ 63,744     $ 59,379     $ 125,600     $ 145,095  

Cash flows used in investing activities

     (943,246 )     (30,645 )     164,433       (77,343 )

Cash flows provided by (used in) financing activities

     979,226       (27,239 )     (290,334 )     (71,498 )
                                

Net increase (decrease) in cash and cash equivalents

   $ 99,724     $ 1,495     $ (301 )   $ (3,746 )
                                

Operating Activities. Key drivers of net cash provided by operating activities are commodity prices, production volumes and costs and expenses, which primarily include operating costs, taxes other than income taxes, transportation expense and administrative expenses.

Net cash provided from operations for the six months ended December 31, 2005 was $63.7 million generated from total production of 13.5 Bcfe with revenue of $113.1 and net income of $17.5 million. Natural gas prices averaged $8.23 per Mcf, including the effects of hedging, and oil averaged $59.52 per Bbl during this period.

 

51


Table of Contents
Index to Financial Statements

Net cash provided from operating activities for the six months ended June 30, 2005 was $59.4 million generated from total production of 15.5 MMcfe with revenue of 103.8 and net income of $18.7 million. Natural gas prices averaged $6.59 per Mcf and oil averaged $49.86 per Bbl during this period.

Net cash provided by operating activities for the year ended December 31, 2004 decreased $19.5 million from December 31, 2003. The decrease is primarily due to lower production volumes for the year ended December 31, 2003 and 2004, respectively that were slightly offset by higher commodity prices. Production volumes decreased 22% from 52.2 Bcfe to 40.9 Bcfe for the year ended December 31, 2003 and 2004, respectively. The average realized prices increased 12% from $5.38 per Mcf in 2003 to $6.02 per Mcf in 2004.

Investing Activities. The primary driver of cash used in investing activities is capital spending and sale of properties.

Cash used in investing activities for the six months ended December 31, 2005 was $943.2 million primarily relating to the acquisition of the domestic oil and gas business of Calpine in the net cash amount of $910 million (excluding fees, purchase price adjustments and expenses) and $32 million in capital expenditures spent after the acquisition. We withheld approximately $75 million from the aggregate purchase price as the allocated dollar amount for the non-consent properties, which amount is essentially equivalent to the PV-10 value of those properties at April 30, 2005, the date of the modified roll forward of our proved reserves by Netherland, Sewell & Associates, Inc. If the assignment of these cured non-consent properties does not occur, the portion of the purchase price we held back pending obtaining consent will be retained by us and will be available to us for general corporate purposes.

Cash used in investing activities for the six months ended June 30, 2005 was $30.6 million related to capital expenditures of $32.2 million related to drilling and completion work and lease acquisitions less sale of assets.

Cash used in investing activities increased by $241.8 million from 2003 to 2004 primarily due to the completed sale of our Rocky Mountain natural gas properties that were primarily concentrated in the two geographic areas of the Colorado Piceance Basin and the New Mexico San Juan Basin. As a result of the sale, Calpine recorded income from discontinued operations, net of tax of $68.4 million.

Financing Activities. The primary driver of cash provided (used) in financing activities is equity transactions, the acquisition of new debt facilities or increase in intercompany notes payable and corresponding repayments of debt.

Net cash used in financing activities for the six months ended December 31, 2005 was $979.2 million. This was due to receipt of $800 million in equity offering proceeds net of $55.6 million in transaction fees and draws on our $325 million senior credit facility subsequently used for the acquisition of the oil and natural gas properties of Calpine, operating needs, the repayment of $85.0 million of long-term debt and $5.1 million of deferred loan costs.

Net cash used in financing activities for the six months ended June 30, 2005 was comprised of repayments of notes to affiliates totaling $27.2 million.

Net cash used in financing activities increased $218.8 million from $71.5 million for the year ended December 31, 2003 to $290.3 million for the year ended December 31, 2004. The variance is due primarily to cash used in discontinued operations of approximately $219 million, resulting from asset sales.

Commodity Prices and Related Hedging Activities

The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. To mitigate our exposure to changes in

 

52


Table of Contents
Index to Financial Statements

commodity prices, management has adopted a policy of hedging oil and natural gas prices from time to time primarily through the use of certain derivative instruments including fixed price swaps, costless collars, and put options. Although not risk free, we believe this policy will reduce our exposure to commodity price fluctuations and thereby achieve a more predictable cash flow. Consistent with this policy, and in connection with entering into our credit facilities in July 2005, we have entered into a series of natural gas fixed-price swaps, which are intended to establish a fixed price for a significant portion of our expected natural gas production through 2009. The fixed-price swap agreements we have entered into require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected proved production from existing wells at inception of the hedge instruments.

Consistent with our hedge policy, in December 2005 we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for a portion of our expected production in 2006. If the floating price each month at the settlement point is greater than the ceiling price, we pay the counterparty an amount equal to the positive difference between the floating price and the ceiling price multiplied by the notional volume for the contract month. If the floating price for each month is less than the floor price, the counterparty pays us an amount equal to the positive difference between the floating price and the floor price multiplied by the notional volume for the contract month. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk”.

In accordance with SFAS 133, as amended, all derivative instruments are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair market value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions every three months, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair market value of the ineffective portion of cash flow hedges are included in other revenue.

Our current hedge positions are with counterparties that are lenders in our credit facilities. This allows us to securitize any margin obligation resulting from a negative change in the fair market value of the derivative contracts in connection with our credit obligations and eliminate the need for independent collateral postings. As of December 31, 2005, we had no deposits for collateral.

The following table sets forth the results of third party hedging transactions settled for the six months ended December 31, 2005:

 

Natural gas

  

Quantity settled (MMBtu)

     7,956,000  

Increase (Decrease) in Natural Gas Sales Revenue

   $ (16,575,709 )

In connection with the acquisition, we did not acquire any derivative positions or hedging agreements.

Interest Rate Risks

Borrowings under our term and revolving line of credit facilities mature on July 7, 2009 and bear interest at a LIBOR-based rate. This exposes us to risk of earnings loss due to changes in market rates. Although we continue to evaluate the risks related to this exposure, we have not entered into any interest rate swap agreements to mitigate such risk as of December 31, 2005. If we determine the risk may become substantial and the costs are not prohibitive, we may enter into interest rate swap agreements in the future.

 

53


Table of Contents
Index to Financial Statements

Capital Requirements

The following table summarizes information regarding historical capital expenditures for the six months ended December 31, 2005 (successor), the six months ended June 30, 2005 (predecessor) and the historical capital expenditures for the year ended December 31, 2004 (predecessor).

 

     Successor    Predecessor
    

Six Months

Ended

December 31,

2005

  

Six
Months

Ended

June 30,

2005

  

Year

Ended

December 31,

2004

         (In thousands)

Development capital expenditures:

        

Sacramento Basin

   $ 3,930    $ 4,166    $ 6,025

Lobo

     6,775      2,001      8,670

Perdido

     9,268      10,874      7,422

Texas State Waters

     2,499      —        —  

Other Onshore

     3,833      1,337      5,164

Gulf of Mexico

     2,947      246      1,813

Rocky Mountains

     3,035      965      —  

Mid-Continent

     317      220      300
                    

Total development capital expenditures

     32,604      19,809      29,394

Exploration capital expenditures:

        

Exploration activities:

        

Sacramento Basin

     3      406      2,214

Lobo

     —        19      —  

Perdido

     —        1,567      11,261

Texas State Waters

     524      3,417      —  

Other Onshore

     6,998      963      3,043

Gulf of Mexico

     6,422      4,310      2,361

Rocky Mountains

     —        137      —  

Mid-Continent

     —        —        —  

Leasehold

     9,224      2,617      3,559

New acquisitions

     5,524      —        —  

Delay rentals

     143      443      507

Geological and geophysical/Seismic

     5,659      513      199
                    

Total exploration capital expenditures

     34,497      14,392      23,144
                    

Total capital expenditures(1)

   $ 67,101    $ 34,201    $ 52,538
                    

(1) The amount for 2004 (predecessor) excludes $1.3 million of capitalized interest, $3.1 million of overhead, $10.0 million of compressor station and gathering system expense and $1.4 million for acquisition properties. Our total capital expenditures in 2004 of $52 million, including these exclusions, corresponds to 2004 total capital costs of $69 million as defined under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” in the Supplemental Oil and Gas Disclosure in Item 8. The six-month period ended June 30, 2005 (predecessor) excludes $(0.7) million of capitalized interest and $1.7 million of overhead. Capital expenditures for the six months ended December 31, 2005 (successor) excludes $0.6 million of capitalized interest, $1.6 of corporate other and geological and geophysical costs of $1.7 million. Corporate other consists of corporate costs related to IT software/hardware, office furniture and fixtures and license transfer fees.

After the completion of the acquisition of the oil and natural gas properties and our separation from Calpine, our capital expenditures for the six months ended December 31, 2005 increased by approximately $33 million in

 

54


Table of Contents
Index to Financial Statements

relation to what Calpine spent in the first six months of 2005. We expect to continue this trend of increased capital expenditures in 2006 with a capital budget for the year ended December 31, 2006 of approximately $199 million.

We expect to fund this capital expenditure budget out of available cash and cash flow from operations and, if necessary, from our available borrowing base under our credit facilities. If cash and cash flows are not adequate, we may not be able to fund the amounts set forth above without incurring further indebtedness or accessing the equity or debt capital markets.

Commitments and Contingencies

Commitments

As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is management’s belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

Contractual Obligations. At December 31, 2005, the aggregate amounts of our contractually obligated payment commitments for the next five years are as follows:

 

     Payments Due by Period
Contractual Obligations    Total    2006    2007
to 2008
  

2009

to 2010

   2011 and
Beyond
     (In thousands)

Senior secured revolving line of credit

   $ 165,000    $ —      $ —      $ 165,000    $ —  

Second lien term loan

     75,000      —        —        75,000      —  

Operating leases

     15,605      1,924      3,891      3,898      5,892

Interest payments on long-term debt

     65,914      16,654      33,947      15,313      —  

Rig commitments

     18,667      17,092      1,575      —        —  
                                  

Total contractual obligations

   $ 340,186    $ 35,670    $ 39,413    $ 259,211    $ 5,892
                                  

Asset Retirement Obligation. The Company also has liabilities of $9.5 million related to asset retirement obligations on its Consolidated Balance Sheet at December 31, 2005. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 9 of the Consolidated/Combined Financial Statements.

Purchase and Sale Agreement with Calpine. Under our purchase and sale agreement with Calpine, Calpine agreed to transfer to us certain properties, the transfer of which requires the consent of third parties. At the closing of our acquisition in July 2005, title to properties having a value of approximately $75 million remained with Calpine subject to receipt of consents. As provided in the purchase and sale agreement, we retained approximately $75 million in cash, out of the total purchase price pending completion of these assignments. At the time of the Calpine bankruptcy, we were preparing to consummate the assignments of these properties with Calpine (excluding $7.4 million relating to properties for which a preferential right has not been waived). Because of Calpine’s bankruptcy, we may experience delay or frustration of our ability to complete these purchases. If these assignments do not occur, the approximately $75 million retained pending these assignments will be available to us to use for general corporate purposes.

Contingencies

The Company is party to various litigation matters arising out of the normal course of business. Although the ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters, management does not believe any such matters

 

55


Table of Contents
Index to Financial Statements

will have a material adverse effect on the Company’s financial position, results of operation or cash flows. As of December 31, 2005 and 2004, a reserve for legal fees was recorded in other current liabilities on the Consolidated/Combined Balance Sheets in the amount of $0.4 million and $0.1 million, respectively.

Calpine Bankruptcy

Calpine and certain of its subsidiaries (collectively, the “Debtors”) filed for protection under the federal bankruptcy laws in the Southern District of New York on December 20, 2005. The Company is not presently a party to any pending litigation in connection with this bankruptcy, although counsel has filed a notice of appearance on our behalf so we may effectively monitor the proceedings. Calpine Energy Services, L.P. has continued to make the required deposits into Rosetta’s margin account and to timely pay for production it purchases from the Company’s subsidiaries under various supply agreements. Calpine and certain of its subsidiaries have generally continued to provide services desired by the Company under the Transition Services Agreement and Calpine Producer Services, L.P. generally is performing its obligations under the Marketing and Services Agreement with us.

There remains the possibility, however, that there will be issues between the Company and Calpine that could amount to material contingencies in relation to the Purchase and Sale Agreement, dated July 7, 2005 by and among Calpine, the Company and various other parties signatories thereto (the “Purchase Agreement”) including unasserted claims and assessments with respect to (i) the still pending final closing under the Purchase Agreement and the amounts that will be payable in connection therewith, (ii) whether or not Calpine and its affiliated debtors will, in fact, perform their remaining obligations in connection with the final closing, and (iii) the ultimate disposition of certain properties (and related royalty revenues) for which third party consents to transfer had not been obtained at the time of the original closing under the Purchase Agreement. While the Company remains hopeful that it will be able to work cooperatively with Calpine so as to accomplish the delivery by Calpine of record legal title including all ancillary ministerial and administrative corrections for all non-consent properties, as well as the curative corrections for all properties which the Company paid for, all of the same being covered by the further assurances provision of the parties’ definitive agreements, the timing and exact details of how, when and if this will be able to be accomplished continue to remain uncertain at this early stage of Calpine’s bankruptcy. The Company’s management continues to believe that it is unlikely that any challenges by the Calpine debtors or their creditors to the fairness of this acquisition would be successful. At the present time, there is no pending or overtly threatened litigation in this regard. However, in the future there may be possible unasserted claims and assessments, seeking to challenge some aspect of the acquisition.

Deanne Lounsberry Duhon, et al. v. Ensearch Exploration, Inc., et al.

This lawsuit is a retained liability by Calpine. On September 10, 2004, Apache Corporation (“Apache”) filed a cross-claim and third party demand in the above listed matter and has named Calpine Natural Gas and Agricultural Methane in this suit. A dispute has arisen as to the division of royalties between certain groups. The plaintiffs are seeking the forfeiture from Apache of the working interest income stream from the proceeds of the production of the well in various producing intervals. Apache is seeking claims for contribution and indemnifying in the event Apache is found liable. RROLP and Agricultural Methane are currently reviewing these allegations. It is the Company’s understanding that this matter has been settled for an immaterial amount.

Arbitration between Calpine Corp./RROLP and Pogo Producing Company

This is a retained liability by the predecessor. On September 1, 2004, Calpine and RROLP (collectively “Calpine”), sold its New Mexico oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course of the sale, Pogo made a title defect claim (valued at approximately $1.9 million) claiming that certain leases subject to the sale had expired because of lack of production. Although Calpine has undertaken to resolve

 

56


Table of Contents
Index to Financial Statements

this matter by obtaining ratifications of a majority of the questionable leases, Pogo has been unwilling to compromise its claim for the title defect value and has invoked the arbitration provisions of the underlying purchase and sale agreement. It is the Company’s understanding that Calpine has cured 85-90% of alleged title defects. The arbitration is subject to Calpine’s stay and, therefore is on hold. This is a retained liability by Calpine and it is management’s belief that this will have no financial impact to the Company.

Claim for Indemnification by Bill Barrett Corporation

It is the Company’s understanding that this matter has been settled by Bill Barrett. Calpine still has potential contractual indemnification subject to stay. This is a retained liability by Calpine and it is management’s belief that this will have no financial impact to the Company.

Environmental

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. The Company performed an environmental remediation study for three sites in California and correspondingly, recorded a liability, which at December 31, 2005 and 2004 was $0.7 million and $0.7, respectively. We do not expect that the outcome of our environmental matters discussed above will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Participation in a Regional Carbon Sequestration Partnership

In accordance with its obligations to Calpine under the parties’ transition services agreement, the Company has made preliminary preparations in connection with its cooperating with Calpine to participate in a joint study in connection with the U.S. Department of Energy’s (“DOE”) Regional Carbon Sequestration Partnership program (“WESTCARB”) with the California Energy Commission and the University of California, Lawrence Berkeley Laboratory. The Company has been selected by the DOE for this project. Under WESTCARB, the Company would be required to drill a carbon injection well, recondition an idle well for use as an observation well and provide WESTCARB with certain proprietary well data and technical assistance related to the evaluation and injection of carbon dioxide into a suitable natural gas reservoir in the Sacramento Basin. The Company’s maximum contribution to WESTCARB is $1.0 million and will be limited to 20% of the total contributions to the project. The Company will not have any obligation under the WESTCARB project until it has entered into an acceptable contract and the project has obtained proper and necessary local, state and federal regulatory approvals, land use authorizations, and third party property rights. No accrual was recorded at December 31, 2005 as the study is still in the preliminary stage.

Related Party Transactions

Successor

During the six months ended December 31, 2005, the Company purchased accounting contract services from a firm in which a principal partner is related to an officer of the Company. Total expenditures for these services in this period were $0.6 million.

Predecessor

Calpine and certain of its affiliates entered into various agreements with respect to the domestic oil and natural gas properties. Upon acquisition of the oil and natural gas business from Calpine, these various agreements were cancelled or retired. Following is a general description of each of the various agreements in effect prior to the date of acquisition:

Agency Agreement. Calpine entered into a service agreement with Calpine Producer Services (“CPS”) beginning April 1, 2003. The contract was automatically renewed every year unless terminated by either party.

 

57


Table of Contents
Index to Financial Statements

CPS provided services related to the Calpine’s production, including marketing, contract administration, royalty and working interest owner issues, and receipt of payments. All activities performed by CPS were performed on behalf of Calpine and under Calpine’s control and direction, in exchange for a fee for services rendered. Calpine dispensed all royalty payments when CPS provided accurate and timely details. Management fees of $0.9 million for the six months ended June 30, 2005 and $1.9 million and $2.9 million are recorded as Affiliated marketing fees in the combined statements of operations for the years ended 2004 and 2003, respectively.

Natural Gas Sales. Calpine and Calpine Energy Services (“CES”) executed index based natural gas sales under existing master agreements. Many of these transactions were executed by CPS on behalf of Calpine; however, Calpine sold directly to CPS and CES prior to the agency agreement with CPS being executed. Oil and natural gas sales to affiliates were $81.9 million for the six months ended June 30, 2005 and $190.2 million and $223.5 million for the years ended December 31, 2004 and 2003, respectively.

Natural gas balancing activities between CES and Calpine, where Calpine bought back natural gas above the needs of CES and then re-sold that excess natural gas to third parties was recorded net to affiliated marketing fees in the combined statements of operations. The net effect of these balancing activities resulted in a gain or loss in the respective period. The net balancing cost (reduction of cost) for the years ended December 31, 2004 and 2003 was $(0.1) million and $0.3 million, respectively and for the six months ended June 30, 2005 there was no net balancing cost.

Notes Payable to Affiliates. Prior to the acquisition in July 2005, the Company and Calpine had an agreement whereby Calpine loaned the Company funds for capital expenditures, as well as, operating costs. The Company repaid the balance of the note to Calpine as excess cash was available from continuing operations and asset sales. Interest on the note was compounded monthly at an annual rate of 8.75% during 2002 and 2003 and for the period through July of 2004, when the rate became variable, raising from 9.0% in August 2004 to 9.05% in December 2004. Additionally, the Company received equipment transferred from CPN Pipeline Company (“Pipeline”) during 2004 that was transferred at historical cost as the transaction was between entities under common control. The Company’s payable to Pipeline was subsequently transferred to Calpine and increased the note discussed above. As part of certain credit facilities entered into by Calpine, the security included direct liens on the domestic oil and natural gas properties. The balance of Notes payable to Affiliates was $127.2 million and $444.1 million at December 31, 2004 and 2003, respectively. These notes were retired at the time of acquisition of the oil and natural gas business of Calpine.

Other Services. Calpine provided general services to other subsidiaries of Calpine that were recorded in accounts receivables from affiliates on the combined balance sheets and other revenue on the combined statements of operations, which were insignificant.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

FORWARD-LOOKING STATEMENTS

In addition to historical information, this Annual Report contains forward-looking statements within the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements include any projections of earnings, revenues, asset sales, cash flow, debt levels or other financial items; any statements of the plans, strategies and objectives of management for future operation; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing. Forward-looking statements may include the words “may”, “will”, “estimate”, “intend”, “believe”, “expect”, “project”, “forecast”, “plan”, “anticipate” and other similar words.

 

58


Table of Contents
Index to Financial Statements

Item 7A. Quantitative and Qualitative Disclosure About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk. Our major market risk exposure is in the pricing of our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Based on daily production for the year ended December 31, 2005, our annual income before income taxes would change by approximately $2.7 million for each $0.10 change in natural gas prices and approximately $350,000 for each $1.00 change in crude oil prices.

We use derivative transactions to manage exposure to commodity prices. Our objectives for holding derivative instruments are to achieve a consistent level of cash flow to support a portion of our planned capital spending. Our use of derivative transactions for hedging activities could materially affect our results of operations, in particular quarterly or annual periods since such instruments can limit our ability to benefit from favorable price movements. We do not enter into derivative instruments for trading purposes.

We believe the use of derivative transactions, although not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our derivative contracts generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivative contracts will vary from time to time.

Our fixed-price swap agreements are used to fix the sales price for our anticipated future oil and natural gas production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us. We have designated these swaps as cash flow hedges.

As of December 31, 2005, we had the following financial fixed price swap positions outstanding with average underlying prices that represent hedged prices of commodities at various market locations:

 

 

Settlement Period

  

Derivative
Instrument

  

Hedge
Strategy

   Notional
Daily
Volume
MMBtu
  

Total of

Natural

Notional Annual

Volume
MMBtu

   Average
Fixed Price
per
MMBtu
   Total of
Proved Natural
Gas Production
Hedged(1)
       
                    Fair Value
Gain/(Loss)
(In thousands)
 

2006

   Swap    Cash flow    45,000    16,425,000    $ 7.923    46 %   $ (29,958 )

2007

   Swap    Cash flow    36,300    13,249,500    $ 7.617    33 %     (25,817 )

2008

   Swap    Cash flow    30,876    11,300,616    $ 7.297    27 %     (16,931 )

2009

   Swap    Cash flow    26,141    9,541,465    $ 6.989    26 %     (10,230 )
                           

Total

            50,516,581         $ (82,936 )
                           

(1) Estimated based on net gas reserves presented in the December 31, 2005 Netherland, Sewell & Associates, Inc. reserve report.

 

59


Table of Contents
Index to Financial Statements

Consistent with our hedge policy, in December 2005 we entered into two costless collar transactions, which are intended to establish a floor price and ceiling price for a portion of our expected production in 2006. If the floating price each month at the settlement point is greater than the ceiling price, we pay the counterparty an amount equal to the positive difference between the floating price and the ceiling price multiplied by the notional volume for the contract month. If the floating price for each month is less than the floor price, the counterparty pay us an amount equal to the positive difference between the floating price and the floor price multiplied by the notional volume for the contract month.

The following table describes our open costless collar transactions at December 31, 2005 by associated notional volumes and contracted ceiling and floor price at various market locations:

 

 

Settlement Period

   Derivative
Instrument
   Hedge
Strategy
   Notional
Daily
Volume
MMBtu
  

Total of

Natural
Notional Annual
Volume
MMBtu

   Average
Floor Price
per
MMBtu
   Average
Ceiling Price
per MMBtu
    
                    

Fair Value

Gain/(Loss)

(In thousands)

2006

   Costless
Collar
   Cash
flow
   10,000    3,650,000    $ 8.825    $ 14.000    $ 1,110

The total of proved natural gas production hedged in 2006 for the costless collars is approximately 10% based on the December 31, 2005 reserve report prepared by Netherland, Sewell & Associates, Inc.

Interest Rate Risks. In July 2005, we entered into our credit facilities including (1) a senior secured revolving line of credit in the aggregate amount of up to $400 million (the “Revolver”), and (2) a senior secured second lien term loan, initially, in the aggregate amount of $100 million (the “Term Loan”). Both the senior secured revolving line of credit and the senior secured second lien loan were amended and syndicated on September 27, 2005.

Availability under the Revolver is restricted to a borrowing base calculation of value assigned to proved oil and natural gas reserves. The initial borrowing base was $275 million and was reset to $325 million as of the syndication date as a result of the derivative transactions and the favorable effects of our underwriters exercising the over-allotment option we granted in connection with our sale of 45,312,500 shares of our common stock, through which we received $70 million of funds (net of transaction fees), were used to repay $60.0 million of borrowings under the Revolver in July 2005 and the remainder for unspecified operating costs of our oil and natural gas properties and general and administrative costs from our oil and natural gas operations. The borrowing base is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our derivative arrangements. Amounts outstanding under the Revolver bear interest at specified margins over the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%, based on facility utilization. The Revolver will mature on July 7, 2009.

The Term Loan initially in the amount of $100 million was reduced to $75 million on the syndication date of September 27, 2005. Borrowings under the Term Loan initially bore interest at LIBOR plus 5.00%. In September 2005, $25 million of borrowings under the Term Loan were repaid. As a result of the derivative transactions and the favorable effect of our private equity placement, as described above, the interest rate for the second lien term loan has been reduced to LIBOR plus 4.00%. The Term Loan is collateralized by a second lien on all assets securing the Revolver. The Term Loan will mature on July 7, 2010.

We had availability under the facility of $160 million as of December 31, 2005. A one hundred basis point increase in each of the LIBOR rate and federal funds rate as of December 31, 2005 for both our revolver of credit and term debt would result in an estimated $2.4 million increase in annual interest expense.

 

60


Table of Contents
Index to Financial Statements

Item 8. Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

 

     Page

Report of Independent Registered Public Accounting Firm

   62

Report of Independent Registered Public Accounting Firm

   63

Consolidated/Combined Balance Sheets at December 31, 2005 (successor) and 2004 (predecessor)

   64

Consolidated/Combined Statements of Operations for the six months ended December 31, 2005 (successor) and June 30, 2005 (predecessor) and for the years ended December 31, 2004 and 2003 (predecessor)

   65

Consolidated/Combined Statements of Cash Flows for the six months ended December 31, 2005 (successor) and June 30, 2005 (predecessor) and for the years ended December 31, 2004 and 2003 (predecessor)

   66

Consolidated/Combined Statements of Changes in Stockholders’ Equity and Comprehensive Income for the six months ended December 31, 2005 (successor) and Changes in Owner’s Net Investment for the six months ended June 30, 2005 (predecessor) and for the years ended December 31, 2004 and 2003 (predecessor)

   68

Notes to Consolidated/Combined Financial Statements

   69

 

61


Table of Contents
Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Rosetta Resources Inc.:

In our opinion, the consolidated balance sheet as of December 31, 2005 and the related consolidated statements of operations, of cash flows and of changes in stockholders’ equity and comprehensive income for the six months ended December 31, 2005 present fairly, in all material respects, the consolidated financial position of Rosetta Resources Inc. and its subsidiaries (successor, the “Company”) at December 31, 2005 and the results of their operations and their cash flows for the six months ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note 11 to the consolidated financial statements, the Company’s former parent filed bankruptcy subsequent to the Company’s acquisition of the oil and natural gas business of Calpine Corporation and Affiliates.

/s/ PricewaterhouseCoopers LLP

April 19, 2006

Houston, Texas

 

62


Table of Contents
Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors

and Stockholders of Rosetta Resources Inc.:

In our opinion, the combined balance sheet as of December 31, 2004 and the related combined statements of operations, of cash flows and of changes in owner’s net investment for the six months ended June 30, 2005 and each of the two years in the period ended December 31, 2004 present fairly, in all material respects, the combined financial position of the Domestic Oil & Natural Gas Properties of Calpine Corporation and Affiliates (predecessor) at December 31, 2004 and the results of their operations and their cash flows for the six months ended June 30, 2005 and each of the two years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 3 to the combined financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.

As described in Note 17 to the combined financial statements, the Company has significant transactions and relationships with related parties. Because of these relationships, it is possible that the terms of these transactions are not the same as those that would result from transactions among wholly unrelated parties.

/s/ PricewaterhouseCoopers LLP

April 19, 2006

Houston, Texas

 

63


Table of Contents
Index to Financial Statements

ROSETTA RESOURCES INC.

CONSOLIDATED/COMBINED BALANCE SHEETS

 

     Successor-
Consolidated
     Predecessor-
Combined
 
     December 31,
2005
     December 31,
2004
 
     (In thousands, except share
amounts)
 

Assets

     

Current Assets:

     

Cash and cash equivalents

   $ 99,724      $ —    

Accounts receivable

     40,051        11,803  

Accounts receivable from affiliates

     —          23,008  

Derivative instruments

     1,110        —    

Deferred income taxes

     10,962        —    

Current income tax receivable

     6,000        —    

Other current assets

     9,411        3,665  
                 

Total current assets

     167,258        38,476  
                 

Oil and natural gas properties, full cost, of which $37 million was excluded from amortization at December 31, 2005/successful efforts method

     973,185        1,105,560  

Other

     2,912        5,956  
                 
     976,097        1,111,516  

Accumulated depreciation, depletion, and amortization

     (40,161 )      (504,996 )
                 

Total property and equipment, net

     935,936        606,520  

Long-term accounts receivable

     1,726        3,137  

Deferred loan fees

     4,555        —    

Deferred income taxes

     8,594        —    

Other assets

     1,200        8,395  
                 

Total other assets

     16,075        11,532  
                 

Total assets

   $ 1,119,269      $ 656,528  
                 

Liabilities, Stockholder's Equity and Owner’s Net Investment

     

Current Liabilities:

     

Accounts payable

   $ 13,442      $ 4,494  

Notes payable to affiliates

     —          127,164  

Royalties payable

     30,039        10,768  

Current income tax payable

     —          114,589  

Derivative instruments

     29,957        —    

Interest payable

     133        —    

Prepayment on gas sales

     14,528        —    

Other current liabilities

     13,736        21,969  
                 

Total current liabilities

     101,835        278,984  

Long-term liabilities

     

Derivative instruments

     52,977        —    

Long-term debt

     240,000        —    

Asset retirement obligation

     9,034        8,384  

Deferred income taxes

     —          145,709  
                 

Total liabilities

     403,846        433,077  

Commitments and Contingencies (Note 11)

     

Stockholders' Equity and Owner's Net Investment:

     

Common Stock, $0.001 par value, 150,000,000 shares authorized, 50,003,500 issued and outstanding

     50        —    

Additional paid-in capital

     748,569        —    

Owner’s net investment

     —          223,451  

Accumulated other comprehensive loss

     (50,731 )      —    

Retained earnings

     17,535        —    
                 

Total stockholders' equity and owner's net investment

     715,423        223,451  
                 

Total liabilities, stockholders' equity and owner's net investment

   $ 1,119,269      $ 656,528  
                 

The accompanying notes to the financial statements are an integral part hereof.

 

64


Table of Contents
Index to Financial Statements

ROSETTA RESOURCES INC.

CONSOLIDATED/COMBINED STATEMENTS OF OPERATIONS

 

     Successor-
Consolidated
     Predecessor-Combined  
    

Six Months
Ended

December 31,
2005

    

Six Months
Ended

June 30,
2005

    Year Ended
December 31,
2004
    Year Ended
December 31,
2003
 
     (In thousands, except share and per share amounts)  

Revenues:

         

Oil sales

   $ 11,046      $ 8,166     $ 23,443     $ 10,386  

Natural gas sales

     102,044        13,637       34,129       45,844  

Oil and natural gas sales to affiliates

     —          81,952       190,215       223,464  

Other revenue

     14        76       219       222  
                                 

Total revenues

     113,104        103,831       248,006       279,916  

Operating Costs and Expenses:

         

Lease operating expense

     15,674        16,629       30,785       29,586  

Depreciation, depletion, and amortization

     40,500        30,679       81,590       72,766  

Exploration expense

     —          2,355       5,352       4,105  

Dry hole costs

     —          1,962       2,088       12,624  

Impairment

     —          —         202,120       2,931  

Treating and transportation

     1,286        1,998       3,509       4,759  

Affiliated marketing fees

     —          913       1,887       2,856  

Marketing fees

     1,379        —         —         —    

Production taxes

     3,975        2,755       4,322       3,725  

General and administrative costs

     14,687        9,677       19,416       16,736  
                                 

Total operating costs and expenses

     77,501        66,968       351,069       150,088  
                                 

Operating income (loss)

     35,603        36,863       (103,063 )     129,828  

Other (income) expense

         

Interest expense with affiliates, net of interest capitalized

     —          6,995       28,034       19,050  

Interest expense, net of interest capitalized

     8,216        —         —         —    

Interest income

     (1,837 )      (516 )     (726 )     (62 )

Other (income) expense, net

     152        207       (3,010 )     (547 )
                                 

Total other expense

     6,531        6,686       24,298       18,441  
                                 

Income (loss) before provision for income taxes, discontinued operations and cumulative effect of change in accounting principle

     29,072        30,177       (127,361 )     111,387  

Provision (benefit) for income taxes

     11,537        11,496       (48,525 )     44,508  
                                 

Income (loss) before discontinued operations and cumulative effect of change in accounting principle

     17,535        18,681       (78,836 )     66,879  

Discontinued operations, net of taxes

     —          —         68,440       4,405  

Cumulative effect of change in accounting principle, net of taxes

     —          —         —         156  
                                 

Net income (loss)

   $ 17,535      $ 18,681     $ (10,396 )   $ 71,440  
                                 

Earnings (loss) per share:

         

Basic

         

Income (loss) before provision for income taxes, discontinued operations and cumulative effect of change in accounting principle

   $ 0.35      $ 0.37     $ (1.58 )   $ 1.34  

Discontinued operations

   $ —        $ —       $ 1.37     $ 0.09  

Cumulative effect of change in accounting principle

   $ —        $ —       $ —       $ —    
                                 

Net income (loss)

   $ 0.35      $ 0.37     $ (0.21 )   $ 1.43  
                                 

Diluted