UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the Quarterly Period Ended September 30, 2011
Or
For the Transition Period From to
Commission File Number 0-7406
PrimeEnergy Corporation
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. employer
Identification No.)
One Landmark Square, Stamford, Connecticut 06901
(Address of principal executive offices)
(203) 358-5700
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
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 filings required for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The number of shares outstanding of each class of the Registrant’s Common Stock as of November 8, 2011 was: Common Stock, $0.10 par value 2,718,893 shares.
Index to Form 10-Q
September 30, 2011
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
Condensed Consolidated Statements of Operations – Nine and Three Months Ended September 30, 2011 and 2010
Condensed Consolidated Statement of Stockholders’ Equity – Nine Months Ended September 30, 2011
Condensed Consolidated Statement of Comprehensive Income – Nine Months Ended September 30, 2011 and 2010
Condensed Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2011 and 2010
Notes to Condensed Consolidated Financial Statements – September 30, 2011
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Reserved
Item 5. Other Information
Item 6. Exhibits
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PART I—FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheets – Unaudited
(Thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Other current assets
Total current assets
Property and equipment, at cost
Oil and gas properties (successful efforts method), net
Field service equipment and other, net
Net property and equipment
Other assets
Total assets
LIABILITIES and STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable
Accrued liabilities
Current portion of asset retirement and other long-term obligations
Derivative liability short term
Due to related parties
Total current liabilities
Long-term bank debt
Indebtedness to related parties
Asset retirement obligations
Derivative liability long term
Deferred income taxes
Stockholders’ equity
Common stock, $.10 par value; 2011 and 2010: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2011: 2,731,329 shares; outstanding 2010: 2,802,053 shares
Paid in capital
Retained earnings
Treasury stock, at cost; 2011: 1,105,068 shares; 2010 1,034,344 shares
Total stockholders’ equity – PrimeEnergy
Non-controlling interest
Total stockholders’ equity
Total liabilities and stockholders’ equity
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
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Condensed Consolidated Statements of Operations – Unaudited
(Thousands of dollars, except per share amounts)
Revenues
Oil and gas sales
Realized gain on derivative instruments, net
Field service income
Administrative overhead fees
Unrealized gain (loss) on derivative instruments, net
Other income
Total revenue
Costs and expenses
Lease operating expense
Field service expense
Depreciation, depletion and amortization and accretion on discounted liabilities
General and administrative expense
Exploration costs
Total costs and expenses
Gain on sale and exchange of assets
Income from operations
Other income and expenses
Less: Interest expense
Add: Interest income
Income before provision for income taxes
Provision for income taxes
Net income
Less: Net income attributable to non-controlling interest
Net income attributable to PrimeEnergy
Basic income per common share
Diluted income per common share
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Condensed Consolidated Statement of Stockholders’ Equity – Unaudited
Nine Months Ended September 30, 2011
Balance at December 31, 2010,
Purchase 70,724 shares of common stock
Purchase of non-controlling interests
Distributions to non-controlling interests
Balance at September 30, 2011
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Condensed Consolidated Statements of Comprehensive Income – Unaudited
Other comprehensive income, net of taxes:
Reclassification adjustment for settled contracts, net of taxes of $0 and $125,000, respectively
Changes in fair value of hedge positions, net of taxes of $0 and $5,000, respectively
Total other comprehensive income
Comprehensive income
Less: Comprehensive income attributable to non-controlling interest
Comprehensive income attributable to PrimeEnergy
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Condensed Consolidated Statements of Cash Flows – Unaudited
OPERATING ACTIVITIES
Net Income
Adjustments to reconcile net income to net cash provided by operating activities:
Non-controlling interest in earnings of partnerships
Depreciation, depletion, amortization and accretion on discounted liabilities
Gain on sale of properties
Unrealized gain on derivative instruments, net
Provision for deferred income taxes
Changes in assets and liabilities:
(Increase) decrease in accounts receivable
(Increase) decrease in other assets
Increase (decrease) in accounts payable
Increase in accrued liabilities
Increase (decrease) in due to related parties
Net cash provided by operating activities
INVESTING ACTIVITIES
Capital expenditures, including exploration expense
Proceeds from sale of properties and equipment
Net cash used in investing activities
FINANCING ACTIVITIES
Purchase of stock for treasury
Proceeds from long-term bank debt and other long-term obligations
Repayment of long-term bank debt and other long-term obligations
Repayment of indebtedness to related parties
Distribution to non-controlling interest
Net cash used in financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at the beginning of the period
Cash and cash equivalents at the end of the period
SUPPLEMENTAL DISCLOSURES
Income taxes paid
Income tax refunds received during the year
Interest paid
Change in accrued expenses relating to property
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Notes to Condensed Consolidated Financial Statements
(Unaudited)
(1) Interim Financial Statements:
The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PEC” or the “Company”) have not been audited by independent public accountants. During the interim periods, the Company follows the same accounting policies as used and described in its Annual Report on Form 10-K for the year ended December 31, 2010. In accordance with applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2010 filed with the SEC on April 7, 2011. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010, the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010, the Condensed Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2011, and the Condensed Consolidated Statements of Comprehensive Income and Cash Flows for the nine months ended September 30, 2011 and 2010. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
Recently Issued Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04 “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs”. This ASU amends previously issued authoritative guidance and requires new disclosures, clarifies existing disclosures and is effective for interim and annual periods beginning after December 15, 2011. Early application by public entities is not permitted. The amendments change requirements for measuring fair value and disclosing information about those measurements. Additionally, this ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements and changes certain principles or requirements for measuring fair value or disclosing information about its measurements. For many of the requirements, the FASB does not intend the amendments to change the application of the existing Fair Value Measurements guidance. The Company does not expect this guidance to have a significant impact on its financial position, results of operations or cash flows.
In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income”, which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. The new requirements are effective for public entities for interim and annual periods beginning after December 15, 2011 with early adoption permitted. The adoption of this ASU will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.
In September 2011, the FASB issued ASU No. 2011-08, “Testing Goodwill for Impairment”, which amends the current goodwill impairment testing guidance. Under this accounting update, entities have the option of performing a qualitative assessment before calculating the fair value of the reporting unit when testing goodwill for impairment. If the fair value of the reporting unit is determined, based on qualitative factors, to be more likely than not less than the carrying amount of the reporting unit, then entities are required to perform the two-step goodwill impairment test. This ASU is effective for fiscal years beginning after December 15, 2011, with early adoption permitted. The adoption of this ASU will not have an impact on the Company’s consolidated financial position, results of operations or cash flows as it is a change in application of the goodwill impairment test only.
(2) Acquisitions and Dispositions:
Historically the Company has repurchased the interests of the partners and trust unit holders in the eighteen oil and gas limited partnerships (the “Partnerships”) and the two asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company purchased such interests in an amount totaling $192,000 and $6,000 for the nine months ended September 30, 2011and 2010, respectively.
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(3) Restricted Cash and Cash Equivalents:
Restricted cash and cash equivalents include $7,267,000 and $6,131,000 at September 30, 2011 and December 31, 2010, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2011 and December 31, 2010 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the Condensed Consolidated Balance Sheet.
(4) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:
Accounts Receivable:
Joint interest billing
Trade receivables
Other
Less: Allowance for doubtful accounts
Total
Accounts Payable:
Trade
Royalty and other owners
Prepaid drilling deposits
Accrued Liabilities:
Compensation and related expenses
Property costs
Income tax
(5) Property and Equipment:
Property and equipment at September 30, 2011 and December 31, 2010 consisted of the following:
Proved oil and gas properties, at cost
Unproved oil and gas properties, at cost
Less: Accumulated depletion and depreciation
Field service equipment and other
Less: Accumulated depreciation
Total net property and equipment
(6) Long-Term Bank Debt:
Bank Debt:
Effective June 22, 2011, the Company entered into a Second Amendment to the Second Amended and Restated Credit Agreement (“Second Amendment”). The Second Amendment to this $250 million credit facility increased the Company’s borrowing base to $125 million; removed the floor rate component of LIBO rate loans; modified financial reporting requirements to the agent; increased hedging allowances; and allowed for a one-time advance to be made to the Company’s offshore subsidiary. Subject to facility borrowing base availability amounts, the banks approved a one-time advance of up to $16 million to be made from PEC to its offshore subsidiary specifically to be used to pay in full the offshore subsidiary’s
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indebtedness to a related party. The banks required this advance to be made within 30 days after the effective date of the Second Amendment and the Company completed the advance to its offshore subsidiary on June 24, 2011. Under the Second Amendment, the maximum percentage of production available to enter into commodity hedge agreements was revised to 90% from 85% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, following the Second Amendment the Company’s restriction on payments for dividends, distributions or repurchase of PEC’s stock was increased from $1.0 million to $2.5 million in each calendar year. Borrowing base monthly reduction amounts remain at $2 million with the first reduction to now begin on December 15, 2011.
The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at September 30, 2011) plus applicable margin utilization rates that range from 1.75% to 2.0%, and LIBO rate loans at LIBO published rates plus applicable utilization rates (2.75% to 3.00% at September 30, 2011). As of September 30, 2011, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.97%, respectively.
At September 30, 2011, the Company had $69.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.05% and $55.5 million available for future borrowings. The combined weighted average interest rates paid on outstanding bank borrowings subject to base rate and LIBO interest were 5.04% during the first nine months of 2011 as compared to 6.11% during the same period in 2010.
Indebtedness to related parties:
Effective January 3, 2011, the Company’s loan with a private lender that is controlled by a Director of PEC was modified and provided for a payment from the Company’s offshore subsidiary to the private lender of $4.0 million. On January 18, 2011, the Company’s offshore subsidiary made a $4.0 million payment on this loan. Further, on June 27, 2011, this loan along with all accrued interest was paid in full from the Company’s offshore subsidiary and the note was cancelled.
(7) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the rest of the fiscal 2011 and thereafter for the operating leases are as follows:
2011
2012
2013
2014
Total minimum payments
Rent expense for office space for the nine months ended September 30, 2011 and 2010 was $588,000 and $588,000, respectively.
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2011 is as follows:
Asset retirement obligation – December 31, 2010
Liabilities incurred
Liabilities settled
Accretion expense
Asset retirement obligation – September 30, 2011
The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
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(8) Contingent Liabilities:
The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. As of September 30, 2011, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities and the Company believes these reserves will be sufficient to satisfy Partnership obligations.
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
(9) Stock Options and Other Compensation:
In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2011 and 2010, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
(10) Related Party Transactions:
The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in amounts totaling $192,000 and $6,000 for the nine months ended September 30, 2011 and 2010, respectively.
Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.
Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses. Also included in due to related parties at December 31, 2010 was the amount of accrued interest, $170,000, owed to a related party, a company controlled by a Director of the Company, with whom the Company’s offshore subsidiary entered into a credit agreement. This agreement was concluded as of June 2011 and all interest owed and the loan balance remaining was paid at that time.
(11) Financial Instruments
Fair Value measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010:
Assets
Commodity derivative contracts
Liabilities
Total liability
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December 31, 2010
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy for the nine months ended September 30, 2011.
Net liabilities – December 31, 2010
Total realized and unrealized gains or losses:
Included in earnings (a)
Purchases, sales, issuances and settlements
Net assets – September 30, 2011
Derivative Instrument:
The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with derivative instruments are recognized in earnings.
The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010:
Balance Sheet Location
Asset Derivatives:
Derivatives not designated as hedging instruments:
Natural gas commodity contracts (a)
Crude oil commodity contracts
Liability Derivatives:
Total derivative instruments
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The following table sets forth the effect of derivative instruments on the condensed consolidated statement of operations for the nine-month periods ended September 30, 2011 and 2010:
Location of gain/loss reclassifiedfrom OCI into income
Derivatives designated as cash-flow hedges
Interest rate swap derivatives
Location of gain/loss recognizedin income
Derivatives not designated as cash-flow hedge instruments
Natural gas commodity contracts
Crude oil commodity contracts (a)
(12) Earnings Per Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:
Basic
Effect of dilutive securities:
Options
Diluted
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This report may contain statements relating to the future results of the Company that are considered “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely”‘ “and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward looking statements are made as of the date of this report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statement or to update the reasons why actual results could differ from those projected in the forward-looking statements.
This discussion should be read in conjunction with the condensed consolidated financial statements of the Company and notes thereto.
OVERVIEW
We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, the Gulf of Mexico, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated income statement as changes occur in the NYMEX price indices.
RECENT ACTIVITIES
During the first nine months of 2011, we continued our drilling program in our West Texas district, drilling a total of 21 gross (13.8 net) wells, all of which were successful completions. We intend to drill approximately 30 wells this year, primarily in the West Texas area.
In June 2011, we successfully completed an amendment of our $250 million credit facility with an increase in the borrowing base from $100 million to $125 million and closed our previously existing subordinated credit facility with a related party private lender.
RESULTS OF OPERATIONS
Oil and gas sales increased $3.0 million, or 16% from $18.7 million for the third quarter 2010 to $21.7 million for the third quarter 2011 and $4.2 million, or 7% from $61.0 million for the nine months ended September 30, 2010 to $65.2 million for the nine months ended September 30, 2011. Crude oil and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $8.01 per barrel, or 11% and $1.45 per mcf, or 27% on crude oil and natural gas, respectively, during the third quarter 2011 from the same period in 2010. Our realized prices at the well
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head increased an average of $16.21 per barrel, or 22% and $0.72 per mcf, or 13% on crude oil and natural gas, respectively, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010.
Our crude oil production increased by 12,000 barrels, or 8% from 143,000 barrels for the third quarter 2010 to 155,000 barrels for the third quarter 2011 and decreased 13,000 barrels, or 3% from 471,000 barrels for the nine months ended September 30, 2010 to 458,000 barrels for the nine months ended September 30, 2011. Our natural gas production decreased by 191,000 mcf, or 13% from 1,485,000 mcf for the third quarter 2010 to 1,294,000 mcf for the third quarter 2011 and 853,000 mcf, or 19% from 4,556,000 mcf for the nine months ended September 30, 2010 to 3,703,000 mcf for the nine months ended September 30, 2011. The crude oil production variances are a result of our recent drilling success in West Texas and the Gulf Coast regions as we place new wells into production, partially offset by the natural decline of existing properties. The natural gas volume decreases are primarily due to the natural decline of the primary natural gas producing offshore properties, partially offset by production from wells in the West Texas region recently placed into production.
The following table summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2011 and 2010 (excluding realized gains and losses from derivatives).
Barrels of Oil Produced
Average Price Received (rounded, excluding the impact of derivatives)
Oil Revenue (In 000’s)
Mcf of Gas Produced
Gas Revenue (In 000’s)
Total Oil & Gas Revenue (In 000’s)
Realized net gains on derivative instruments include net gains of $3.3 million and $1.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the third quarter 2011 and $0 and $1.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the third quarter 2010. Realized net gains on derivative instruments include net gains of $1.4 million and $3.0 million on the settlements of crude oil and natural gas derivatives, respectively, for the nine months ended September 30, 2011 and a net loss of $0.1 million and net gain of $2.7 million on the settlements of crude oil and natural gas derivatives, respectively, for the nine months ended September 30, 2010. In August 2011, we unwound and monetized crude oil swaps and collars with original settlement dates from September 2011 through December 2014 for net proceeds of $3.4 million. The $3.4 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the three and nine months ended September 30, 2011.
Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:
Oil Price
Gas Price
We do not apply hedge accounting to any of our commodity based derivatives thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the three months ended September 30, 2011, we recognized $12.5 million in unrealized gains. This unrealized gain consists of $11.4 million associated with crude oil fixed swaps and collars due to a decrease in crude oil futures market prices between June 30, 2011 and September 30, 2011 and $1.1 million associated with natural gas fixed swap contracts due to decreased natural gas futures market prices between June 30, 2011 and September 30, 2011. For the nine months ended September 30, 2011, we recognized $9.0 million in unrealized gains primarily associated with crude oil fixed swaps and collars due to a decrease in crude oil futures market prices between December 31, 2010 and September 30, 2011.
Field service income increased $1.1 million, or 24% from $4.3 million for the third quarter 2010 to $5.4 million for the third quarter 2011 and $3.0 million, or 25% from $12.2 million for the nine months ended September 30, 2010 to $15.2 million for the nine months ended September 30, 2011. This increase is a direct result of upturns in utilization of equipment and the market allowing us to charge
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higher rates to customers. Workover rig services represent the bulk of our field service operations, and those rates all increased in our most active districts. Utilization of our workover rigs increased in all districts. Water hauling and disposal services also increased in our South Texas district
Lease operating expense increased $2.0 million, or 26% from $7.7 million for the third quarter 2010 to $9.7 million for the third quarter 2011 and $1.2 million, or 5% from $25.3 million for the nine months ended September 30, 2010 to $26.5 million for the nine months ended September 30, 2011. These increases are primarily due to higher salt water disposal costs, production taxes and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas, partially offset by decreased operating expenses on the offshore properties and decreased expensed workovers across all districts during the first nine months of 2011.
Field service expense increased $0.8 million, or 22% from $3.6 million for the third quarter 2010 to $4.4 million for the third quarter 2011 and $2.4 million, or 24% from $10.1 million for the nine months ended September 30, 2010 to $12.5 million for the nine months ended September 30, 2011. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased $1.3 million and $1.1 million, respectively, during the nine months ended September 30, 2011 over the same period of 2010 as a direct result of increased services and utilization of the equipment.
Depreciation, depletion, amortization and accretion on discounted liabilities increased $15.6 million from $7.3 million for the third quarter 2010 to $22.9 million for the third quarter 2011 and $16.7 million, or 69% from $24.2 million for the nine months ended September 30, 2010 to $40.9 million for the nine months ended September 30, 2011. Included in these increases is approximately $13.4 million and $14.4 million for the three and nine months ended September 30, 2011, respectively, related to an increased depletion rate recognized during the third quarter of 2011 associated with offshore properties driven by a decrease in estimated remaining economic reserves as several of our offshore properties enter into the last phase of their productive lives. The remaining increases of $2.2 million and $2.3 million for the three and nine months ended September 30, 2011, respectively, primarily relate to the increased production with new wells coming on line from the recent drilling success in West Texas.
Gain on sale and exchange of assets of $1.4 million for the third quarter 2011 consists of $0.5 million related to our Korean Joint Venture combined with $0.9 million related to sales of non-producing acreage and non-core producing properties.
Interest expense decreased $0.9 million, or 58% from $1.6 million for the third quarter 2010 to $0.7 million for the third quarter 2011 and $2.3 million, or 42% from $5.3 million for the nine months ended September 30, 2010 to $3.0 million for the nine months ended September 30, 2011. These decreases include the reduction of interest expense of $0.5 million and $0.7 million for the three and nine months ended September 30, 2011, respectively, associated with interest on the subordinated credit facility with a related party private lender which was paid off in June 2011. The remaining decreases of $0.4 million and $1.6 million for the three and nine months ended September 30, 2011, respectively, relate to reduced weighted average interest rates and less average debt outstanding during the 2011 periods.
LIQUIDITY AND CAPITAL RESOURCES
Our primary capital resources are cash provided by our operating activities and our credit facility.
Net cash provided by our operating activities for the nine month period ended September 30, 2011 was $31.1 million. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico may shut down our production for the duration of the storm’s presence in the Gulf or damage production facilities so that we cannot produce from a particular property for an extended amount of time. In addition, downstream activities on major pipelines in the Gulf of Mexico can also cause us to shut-in production for various lengths of time.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of financial instruments.
Our activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. During 2011, we plan on drilling in excess of 30 wells (20 net), mainly in the Permian Basin in West Texas.
We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2011. For the nine month period ended September 30, 2011, we have spent $1.8 million under these programs.
We currently maintain a credit facility totaling $250 million, with a current borrowing base of $125 million. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these
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covenants. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.
It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. However, the majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company is a smaller reporting company and no response is required pursuant to this Item.
As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II—OTHER INFORMATION
None.
There were no sales of equity securities by the Company during the period covered by this report.
During the nine months ended September 30, 2011, the Company purchased the following shares of common stock as treasury shares.
2011 Month
January
February
March
April
May
June
July
August
September
Total/Average
None
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The following exhibits are filed as a part of this report:
Exhibit No.
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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
/s/ Charles E. Drimal, Jr.
/s/ Beverly A. Cummings
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