UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the Quarterly Period Ended September 30, 2012
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.)
9821 Katy Freeway, Houston, Texas 77024
(Address of principal executive offices)
(713) 735-0000
(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, 2012 was: Common Stock, $0.10 par value 2,580,911 shares.
Index to Form 10-Q
September 30, 2012
Page
Part I - Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2012 and December 31, 2011
Condensed Consolidated Statements of Operations – Nine and Three Months Ended September 30, 2012 and 2011
Condensed Consolidated Statement of Stockholders’ Equity – Nine Months Ended September 30, 2012
Condensed Consolidated Statements of Comprehensive Income – Nine Months Ended September 30, 2012 and 2011
Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011
Notes to Condensed Consolidated Financial Statements – September 30, 2012
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
Part II - Other Information
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
Signatures
2
PART I—FINANCIAL INFORMATION
PRIMEENERGY CORPORATION
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 and office equipment, net
Total Property and Equipment, Net
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
Asset Retirement Obligations
Derivative Liability Long-Term
Deferred Income Taxes
Total Liabilities
Stockholders’ Equity
Common stock, $.10 par value; 2012 and 2011: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2012: 2,594,135 shares; 2011: 2,701,869 shares
Paid-in capital
Retained earnings
Accumulated other comprehensive loss, net
Treasury stock, at cost; 2012: 1,242,262 shares; 2011: 1,134,528 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
3
CONDENSED CONSOLIDATED STATEMENTS OFOPERATIONS – 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 Revenues
Costs and Expenses
Lease operating expense
Field service expense
Depreciation, depletion, 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 Interests
Net Income Attributable to PrimeEnergy
Basic Income Per Common Share
Diluted Income Per Common Share
4
CONDENSED CONSOLIDATED STATEMENT OFSTOCKHOLDERS’ EQUITY – Unaudited
Nine Months Ended September 30, 2012
Balance at December 31, 2011
Purchase 107,734 shares of common stock
Net income
Other comprehensive loss, net of taxes
Purchase of non-controlling interests
Distributions to non-controlling interests
Balance at September 30, 2012
5
CONDENSED CONSOLIDATED STATEMENTS OFCOMPREHENSIVE INCOME – Unaudited
Nine Months Ended September 30, 2012 and 2011
Other Comprehensive Loss, net of taxes:
Changes in fair value of hedge positions, net of taxes of $28 and $0, respectively
Total other comprehensive loss
Comprehensive Income
Less: Comprehensive Income Attributable to Non-controlling Interest
Comprehensive Income Attributable to PrimeEnergy
6
CONDENSED CONSOLIDATED STATEMENTS OF CASHFLOWS – Unaudited
Cash Flows from Operating Activities:
Adjustments to reconcile net income to net cash provided by operating activities:
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
Decrease in accounts payable
Increase in accrued liabilities
Increase in due to related parties
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense
Proceeds from sale of properties and equipment
Net Cash Used in Investing Activities
Cash Flows from Financing Activities:
Purchase of stock for treasury
Proceeds in 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 party
Distribution to non-controlling interests
Net Cash Provided (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 during the period
Income tax refunds received during the period
Interest paid during the period
Increase (decrease) in accrued expenses relating to property during the period
7
NOTES TO CONDENSED CONSOLIDATED FINANCIALSTATEMENTS
(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, 2011. 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, 2011 filed with the SEC on March 29, 2012. 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, 2012 and December 31, 2011, the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011, the Condensed Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2012, the Condensed Consolidated Statements of Comprehensive Income for the nine months ended September 30, 2012 and 2011, and the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011. 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
There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted as of the nine months ended September 30, 2012.
(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 $66,000 and $192,000 for the nine months ended September 30, 2012 and 2011, respectively.
(3) Restricted Cash and Cash Equivalents:
Restricted cash and cash equivalents include $4.59 million and $4.39 million at September 30, 2012 and December 31, 2011, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 2012 and December 31, 2011 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the Condensed Consolidated Balance Sheets.
(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
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Accrued Liabilities:
Compensation and related expenses
Property costs
Income tax
(5) Property and Equipment:
Property and equipment at September 30, 2012 and December 31, 2011 consisted of the following:
Proved oil and gas properties, at cost
Less: Accumulated depletion and depreciation
Oil and Gas Properties, Net
Field and office equipment
Less: Accumulated depreciation
Field and Office Equipment, Net
(6) Long-Term Bank Debt:
Bank Debt:
Effective July 30, 2010 the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is re-determined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be re-determined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.
As of September 30, 2012, the credit facility borrowing base was $125.0 million with no required monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at September 30, 2012) plus applicable margin utilization rates that range from 1.00% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.00% to 3.00%. As of September 30, 2012, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.99%, respectively.
At September 30, 2012, the Company had $110.00 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.62% and $15.00 million available for future borrowings. The combined weighted average interest rates paid on outstanding bank borrowings subject to base rate and LIBO interest were 3.80% for the nine months ended September 30, 2012 as compared to 5.04% for the nine months ended September 30, 2011.
9
(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 2012 and thereafter for the operating leases are as follows:
2012
2013
2014
2015
Total minimum payments
Rent expense for office space for the nine months ended September 30, 2012 and 2011 was $581,000 and $588,000, respectively.
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2012 is as follows:
Asset retirement obligation – December 31, 2011
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated liabilities
Asset retirement obligation – September 30, 2012
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.
In December 2011, the Company entered into a fixed price contract for the plugging and abandonment of a substantial portion of its offshore properties. In connection with this contract, the Company deposited a net $6.0 million with the contractor which is reflected in prepaid obligations at December 31, 2011. All work under this contract was completed by September 30, 2012.
(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, 2012, 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, 2012 and 2011, remaining options held by two key executive officers 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
(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 $66,000 and $192,000 for the nine months ended September 30, 2012 and 2011, respectively.
Treasury stock purchases in any reported period may include shares from a related party, which may include members of the Company’s Board of Directors. In April 2012, the Company purchased 45,179 shares of common stock as treasury shares from a Director for $1.13 million.
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.
(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, 2012 and December 31, 2011:
Assets
Commodity derivative contracts
Total assets
Liabilities
Interest rate derivative contracts
Total liabilities
December 31, 2011
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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, 2012.
Net liabilities – December 31, 2011
Total realized and unrealized gains or losses:
Unrealized gains included in earnings, net (a)
Included in other comprehensive loss
Realized gains from purchases, sales, issuances and settlements, net
Net liabilities – September 30, 2012
Derivative Instruments:
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.
Interest rate swap derivatives are treated has cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at September 30, 2012 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, currently scheduled to begin in January 2014, will be recorded within interest expense.
The following table sets forth the effect of derivative instruments on the condensed consolidated balance sheets as of September 30, 2012 and December 31, 2011:
Balance Sheet Location
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts
Other assets
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts
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, 2012 and 2011:
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.
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material.
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 2012, we continued our drilling program in our West Texas and Mid-Continent regions. Thru October 31, 2012, we have drilled a total of 36 gross (27.25 net) wells, with 33 gross (26.00 net) wells having successful completions, and 2 gross (1.22 net) wells under evaluation. In addition we have 2 gross (0.61 net) wells currently drilling. We intend to drill a total of approximately 40 gross (29 net) wells this year, primarily in the West Texas area.
In February 2012, we closed the acquisition of additional working interest in producing properties which we operate. These properties are located in our Gulf Coast region and were acquired at a net cost of $6.32 million.
During 2012, we began plugging and abandoning the majority of our offshore oil and gas properties. This work was completed by September 30, 2012.
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RESULTS OF OPERATIONS
2012 and 2011 Compared
We reported net income for the three and nine months ended September 30, 2012 of $1.34 million, or $0.51 per share and $10.09 million, or $3.79 per share, respectively as compared to $4.27 million, or $1.56 per share and $5.09 million, or $1.85 per share for the three and nine months ended September 30, 2011, respectively. Net income decreased by $2.93 million for the three months ended September 30, 2012 as compared to the same period during 2011 primarily due to a decrease in unrealized and realized gains on derivative instruments partially offset by decreased depreciation and depletion expenses and income tax provisions. Net income increased by $5.00 million for the nine months ended September 30, 2012 as compared to the same period during 2011 primarily due to decreased depreciation and depletion expenses partially offset by a decrease in unrealized and realized gains on derivative instruments and increased lease operating expenses and income tax provisions. Unrealized gain (loss) on derivative instruments decreased by $15.16 million and $6.57 million for the three and nine months ended September 30, 2012, respectively as compared to the same periods in 2011 largely due to an increase in future crude oil commodity prices during the 2012 periods as compared to crude oil commodity contracts held at the end of the reported periods. Depreciation and depletion decreased by $17.02 million and $21.08 million for the three and nine months ended September 30, 2012, respectively as compared to the same periods in 2011 largely due to decreased depletion rates associated with our offshore properties as several of our offshore properties entered into the last phase of their productive lives.
The significant components of net income are discussed below.
Oil and gas sales increased slightly from $21.76 million for the three months ended September 30, 2011 to $21.81 million for the three months ended September 30, 2012 and increased $0.44 million, or 1% from $65.24 million for the nine months ended September 30, 2011 to $65.68 million for the nine months ended September 30, 2012. 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 $4.40 per barrel, or 5% and $1.65 per barrel, or 2% on crude oil during the three and nine months ended September 30, 2012, respectively from the same periods in 2011 while our average well head price for natural gas decreased $2.13 per mcf, or 31% and $1.90 per mcf, or 29% during the three and nine months ended September 30, 2012, respectively from the same periods in 2011.
Our crude oil production increased by 30,000 barrels, or 19% from 155,000 barrels for the third quarter 2011 to 185,000 barrels for the third quarter 2012 and increased by 83,000 barrels, or 18% from 458,000 barrels for the nine months ended September 30, 2011 to 541,000 barrels for the nine months ended September 30, 2012. Our natural gas production decreased by 103,000 mcf, or 8% from 1,294,000 mcf for the third quarter 2011 to 1,191,000 mcf for the third quarter 2012 and decreased by 210,000 mcf, or 6% from 3,703,000 mcf for the nine months ended September 30, 2011 to 3,493,000 mcf for the nine months ended September 30, 2012. The crude oil production variances are a result of our recent drilling success in West Texas and drilling and acquisition activities in 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, 2012 and 2011 (excluding realized gains and losses from derivatives).
Barrels of Oil Produced
Average Price Received
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 $0.04 million on the settlements of crude oil derivatives for the third quarter 2012 and net gains of $3.30 million and $1.00 million on the settlements of crude oil and natural gas derivatives, respectively, for the third quarter 2011. Realized net gains on derivative instruments include net gains of $0.38 million on the settlements of crude oil derivatives for the nine months ended September 30, 2012 and net gains of $1.46 million and $2.97 million on the settlements of crude oil and natural gas derivatives, respectively, for the nine months ended September 30, 2011. In August 2011, we unwound and monetized crude oil swaps and collars with original settlement dates from September 2011 thru December 2014 for net proceeds of $3.40 million. The $3.40 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. In the nine months ended September 30, 2012, we unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for net proceeds of $1.03 million. The gains associated with these early settlement transactions is included in realized gain on derivative instruments for the nine months ended September 30, 2012.
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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, 2012, we recognized unrealized losses of $2.65 million and a net unrealized gain of $2.45 million for the nine months ended September 30, 2012 associated with crude oil fixed swaps and collars due to market fluctuations in crude oil futures market prices between December 31, 2011 and September 30, 2012. During the three months ended September 30, 2011, we recognized $12.51 million in unrealized gains. This unrealized gain consists of $11.40 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 $1.11 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 $9.01 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 decreased $0.52 million, or 10% from $5.41 million for the third quarter 2011 to $4.89 million for the third quarter 2012 and increased $0.16 million, or 1% from $15.18 million for the nine months ended September 30, 2011 to $15.34 million for the nine months ended September 30, 2012. This underlying increase is a result of upturns in utilization of equipment and the market allowing us to charge slightly 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. Water hauling and disposal services have also increased in our South Texas district, however were slightly down during the third quarter of 2012 due to one of our disposal wells being shut in during the period as a major workover was completed.
Lease operating expense decreased $0.36 million, or 4% from $9.71 million for the third quarter 2011 to $9.35 million for the third quarter 2012 and increased $2.30 million, or 9% from $26.52 million for the nine months ended September 30, 2011 to $28.82 million for the nine months ended September 30, 2012. This underlying increase is primarily due to higher pumper / labor costs, chemical expenses and salt water disposal costs associated with new wells coming on line from the recent drilling success in West Texas and increased expensed workovers across all districts, partially offset by decreased operating expenses on the offshore properties during the first nine months of 2012 as compared to the same period of 2011.
Field service expense decreased $0.12 million, or 3% from $4.39 million for the third quarter 2011 to $4.27 million for the third quarter 2012 and increased $0.48 million, or 4% from $12.54 million for the nine months ended September 30, 2011 to $13.02 million for the nine months ended September 30, 2012. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the nine months ended September 30, 2012 over the same period of 2011 as a direct result of increased services and utilization of the equipment.
Depreciation, depletion, amortization and accretion on discounted liabilities decreased $17.02 million, or 74% from $22.90 million for the third quarter 2011 to $5.88 million for the third quarter 2012 and $21.08 million, or 52% from $40.93 million for the nine months ended September 30, 2011 to $19.85 million for the nine months ended September 30, 2012. This decrease is primarily due to decreased depletion rates recognized during the first nine months of 2012 associated with offshore properties as several of our offshore properties entered into the last phase of their productive lives.
General and administrative expense increased $0.64 million, or 20% from $3.18 million for the three months ended September 30, 2011 to $3.82 million for the three months ended September 30, 2012 and increased $1.29 million, or 13% from $10.22 million for the nine months ended September 30, 2011 to $11.51 million for the nine months ended September 30, 2012. This increase in 2012 is largely due to increased personnel costs in 2012. The largest component of these personnel costs was salaries, however rent, audit related costs and employee related taxes and insurance also contributed to the increase.
Gain on sale and exchange of assets of $0.72 million for the nine months ended September 30, 2012 consists of sales of non-essential field service equipment. Gain on sale and exchange of assets of $1.61 million for the nine months ended September 30, 2011 consists of $0.50 million related to our Korean Joint Venture combined with $1.11 million related to sales of non-essential field service equipment and sales of non-producing acreage and non-core producing properties.
Interest expense increased $0.26 million, or 38% from $0.69 million for the third quarter 2011 to $0.95 million for the third quarter 2012 and decreased $0.51 million, or 17% from $3.04 million for the nine months ended September 30, 2011 to $2.53 million for the nine months ended September 30, 2012. This decrease includes the reduction of interest expense of $0.79 million for the nine
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months ended September 30, 2012 associated with interest on the subordinated credit facility with a related party private lender which was paid off in June 2011. The remaining increase for the three and nine months ended September 30, 2012 relate to reduced weighted average interest rates substantially offset by an increase in average debt outstanding during the 2012 periods.
A provision for income taxes of $0.46 million, or an effective tax rate of 26% was recorded for the three months ended September 30, 2012 verses a provision of $1.90 million, or an effective tax rate of 31% for the three months ended September 30, 2011. A provision for income taxes of $4.67 million, or an effective tax rate of 32% was recorded for the nine months ended September 30, 2012 verses a provision of $2.36 million, or an effective tax rate of 32% for the nine months ended September 30, 2011. Our provision for income taxes varies from the federal statutory tax rate of 34% primarily due to state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis it creates a permanent difference, which lowers our effective rate. The lower effective tax rate in 2012 is primarily due to larger percentage depletion deductions in excess of basis.
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, 2012 was $33.39 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.
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 2012, we plan on drilling approximately 40 wells (29 net), mainly in the Permian Basin in West Texas and in the central Oklahoma area.
In February 2012 we invested a net $6.32 million to acquire additional working interest in producing properties that we operate in our Gulf Coast region. 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.
We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2012. For the nine month period ended September 30, 2012, we have spent $2.77 million under these programs.
We currently maintain a credit facility totaling $250 million, with a current borrowing base of $125 million and $15.00 million in availability at September 30, 2012. 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 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.
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 2012 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, 2012, the Company purchased the following shares of common stock as treasury shares.
2012 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.
19
XBRL information (the Interactive Data File) is deemed not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
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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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