CXPO Crimson Exploration Inc. (MM)

Crimson Exploration Inc. (NasdaqGM:CXPO) today announced financial results for the second quarter and first six months of 2013 and provides operational update.

Highlights

• Revenue of $36.8 million and net income of $0.5 million for the quarter
• Increased oil and liquids production to 3,974 barrels per day, a 29% volume increase over the prior year quarter, 52.4% more than the previous quarter and 54% of total production
• Successfully completed the Grace Hall C #1 and the Payne B #1, both targeting the Woodbine formation, at gross IP rates of 989 Boepd and 1,195 Boepd, respectively.
• Successfully completed the Beeler #2H well, our first in the Buda formation in Dimmit County, TX with a gross IP rate of 859 Boepd (89% oil)
• Committed to a rig for a continuous drilling program in the Buda for the remainder of 2013
• Entered into a stock for stock merger agreement with Contango Oil & Gas that is conditioned on shareholder approval by both parties

Management Commentary

Allan D. Keel, President and Chief Executive Officer, commented, “In April, Crimson entered into the previously announced proposed stock for stock merger with Contango Oil & Gas, a transaction that we believe will afford Crimson shareholders the opportunity to participate in the value to be created from our asset base by accelerating the drilling and development of our extensive set of oil and liquids rich resource plays. While we continue to work hard at closing the merger, we were also successful in establishing the Buda formation as another area of meaningful oil rich drilling opportunities. At a minimum, we intend to keep a rig active for the remainder of the year in each of the Woodbine and Buda plays, and may add another rig to test the Eagle Ford in Madison County, Texas or the James Lime in San Augustine County.”

Merger Status Update

On April 29, 2013, Crimson entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Contango Oil & Gas Company, a Delaware corporation (“Contango”), and Contango Acquisition, Inc., a Delaware corporation and a direct, wholly-owned subsidiary of Contango (“Merger Sub”), providing for a strategic business combination of Crimson and Contango. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into Crimson (the “Merger”), with Crimson continuing as a wholly-owned subsidiary of Contango. The Merger Agreement was approved by each of the board of directors of Crimson and Contango on April 29, 2013.

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each share of Crimson common stock, par value $0.001 per share, issued and outstanding will be converted into the right to receive 0.08288 shares of common stock, par value $0.04 per share, of Contango (“Contango Common Stock”) or, in the case of fractional shares, cash (without interest) in an amount equal to the product of (i) such fractional part of a share of Contango Common Stock multiplied by (ii) the closing price for a share of Contango Common Stock as reported on the New York Stock Exchange on the first trading day following the date on which the Effective Time occurs (the “Merger Consideration”).

The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the adoption of the Merger Agreement by Crimson’s stockholders; (ii) the approval by Contango’s stockholders of the issuance of Contango Common Stock in the Merger to Crimson’s stockholders (the “Share Issuance”); (iii) the registration statement on Form S-4 used to register the Contango Common Stock to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iv) the approval for listing on the New York Stock Exchange of the Contango Common Stock to be issued in the Merger; (v) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (vi) the absence of a material adverse effect with respect to each of Crimson and Contango; and (vii) the delivery of tax opinions that the Merger will be treated as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The Merger Agreement contains certain termination rights for both Crimson and Contango, including, among others, if (i) the Merger is not consummated on or before October 31, 2013; (ii) the requisite approval of the stockholders of either Crimson or Contango is not obtained; and (iii) the other party breaches a representation, warranty or covenant, and such breach results in the failure of closing conditions to be satisfied. The Merger Agreement further provides that for the payment of a termination fee upon the termination of the Merger Agreement under specified circumstances, including termination by Contango or Crimson as a result of (1) an adverse change in the recommendation of the other party’s board of directors or (2) a third-party’s “superior proposal.” The termination fee is $7.0 million (if payable by Crimson) and $28.0 million (if payable by Contango). The Merger Agreement also provides that Crimson or Contango may be required to pay the other party $4.5 million for expense reimbursement if such party’s stockholder approval is not obtained.

Contango and Crimson currently expect the closing of the Merger to occur in September or October of 2013. However, as the Merger is subject to the satisfaction or waiver of other conditions described in the Merger Agreement, it is possible that factors outside the control of Contango and Crimson could result in the Merger being completed at an earlier time, a later time or not at all.

Summary Financial Results

The Company reported net income of $0.5 million, or $0.01 per basic share, for the second quarter of 2013 compared to net income of $3.9 million, or $0.09 per basic share, for the second quarter of 2012. Both quarters included special non-recurring items that impact that comparison. The 2013 quarter includes $1.1 million in special charges to G&A expense related to the merger, a $2.6 million non-cash gain related to the mark-to-market valuation requirement on our commodity price hedges and a $0.8 million leasehold impairment charge. Special items impacting the 2012 quarter were a $4.0 million refund for a portion of 2007-2011 severance taxes received from the State of Texas for certain marketing cost deductions, an unrealized pre-tax gain of $3.0 million related to the mark-to-market valuation requirement on our commodity price hedges and a $0.8 million leasehold impairment charge. Exclusive of these special cash and non-cash items, net income for the 2013 quarter was $0.1 million, compared to a net loss for the second quarter of 2012 of $0.1 million. Adjusted EBITDAX, as defined below, was $24.9 million in the second quarter of 2013, a 2% decrease over adjusted EBITDAX for the prior year quarter of $25.5 million. Exclusive of the merger-related charges in 2013 and the severance tax refund in 2012, adjusted EBITDAX for the 2013 quarter would have been $26.0 million compared to $21.4 million for the 2012 quarter.

Revenues for the second quarter of 2013 were $36.8 million compared to revenues of $30.5 million in the second quarter of 2012. Revenue for the quarter benefited from higher production, a higher percentage of oil and liquids production and higher natural gas prices, offset in part by lower natural gas liquids prices.

Production for the second quarter of 2013 was approximately 4.0 Bcfe, or 44.2 Mmcfe per day, compared to production of approximately 3.7 Bcfe, or 40.4 Mmcfe per day, in the second quarter of 2012. Crude oil and natural gas liquids production averaged 3,974 barrels per day for the second quarter, up 29% over the average in the second quarter of 2012. The increase in total production, as well as in crude and liquids production, was a direct result of our continued success in the Woodbine in Madison and Grimes counties, and initial production from our first Buda well in South Texas.

The weighted average field sales price in the second quarter of 2013 (before the effects of realized gains/losses on our commodity price hedges) was $9.01 per Mcfe compared to an average sales price of $7.60 for the second quarter of 2012. The weighted average realized sales price in the second quarter (including the effects of realized gains/losses on our commodity price hedges) was $9.14 per Mcfe compared to a weighted average realized sales price of $8.30 per Mcfe for the prior year quarter, an increase resulting from the increase in oil and liquids as a percentage of total production and a 31% increase in natural gas prices, offset in part by a 4% decrease in realized oil prices and a 21% decline in natural gas liquids prices.

Direct lease operating expenses for the second quarter of 2013 were $3.3 million, or $0.82 per Mcfe, compared to $3.6 million, or $0.98 per Mcfe, in the second quarter of 2012. Lease operating expenses increased slightly due to the addition of new producing properties, with the improvement in the per unit rate resulting from the addition of those same more cost efficient new properties.

Production and ad valorem tax expenses for the second quarter of 2013 were $2.4 million, or $0.59 per mcfe, compared to a credit of $2.5 million, or ($0.68) per Mcfe in the prior year quarter. The credit in 2012 was due to a $4.0 million refund received from the State of Texas related to allowed marketing cost deductions on certain 2007-2011 severance taxes.

Depreciation, depletion and amortization (“DD&A”) expense for the second quarter of 2013 was $18.6 million, or $4.62 per Mcfe, compared to $14.7 million, or $3.99 per Mcfe, for the second quarter of 2012, with the increase in expense due to higher production and the slightly higher rate resulting from our transition to drilling only higher-margin crude oil wells.

General and administrative expense in the second quarter of 2013 was $6.8 million, or $1.70 per Mcfe, compared to $4.5 million, or $1.23 per Mcfe, in the prior year quarter. Cash general and administrative expenses for the second quarter of 2013, i.e. exclusive of non-cash stock option expense, was $6.1 million, or $1.53 per Mcfe, compared to $3.9 million, or $1.06 per Mcfe, for the second quarter of 2012. Expenses in the second quarter of 2013 increased primarily due to higher personnel costs and merger-related professional fees.

Capital expenditures for the second quarter of 2013 were $19.3 million, consisting of approximately $15.4 million in Southeast Texas targeting the Woodbine formation and $1.9 million in South Texas targeting the Buda formation. Year to date, Crimson has invested approximately $30.4 million in its capital program, with $24.7 million invested in the Woodbine and $1.9 million in the Buda.

Hedging Activity

Crimson continues to mitigate commodity price risk through the use of derivative contracts in an effort to achieve a more predictable cash flow. Consistent with this strategy, in July the following derivative contracts were added to further mitigate crude oil and natural gas liquid price risk for the remainder of 2013:

                            Natural Gas Volume/Month Price/Unit Henry Hub July 2013-Dec 2013 Swap 40,000 Bbls $99.00 (WTI)  

Drilling Update

Woodbine formation

In Madison County, Texas, the Grace Hall C (Allocation) Unit #1H (62.6% WI) well, targeting the Woodbine formation, was successfully completed at a total measured depth of 15,215 feet, including a 6,165 foot lateral, with 22 stages of fracture stimulation, and commenced production in June at an initial rate of 989 boepd (87.7% oil).

Additionally in Madison County, the Payne B #1H (84.1% WI) well, targeting the Woodbine formation, was successfully completed at a total measured depth of 15,900 feet, including a 6,668 foot lateral, with 24 stages of fracture stimulation, and commenced production in May at an initial rate of 1,195 Boepd (87% oil).

Upon completion of drilling operations on the Grace Hall, the rig moved approximately 9 miles southeast to begin drilling the Stuckey-Upchurch #1H (72% WI) well in Crimson’s Iola-Grimes Area, another Woodbine target. The Stuckey well was drilled to a total measured depth of 14,963 feet with a 5,100 foot lateral. Completion operations are scheduled to begin in early August, and are planned to include 19 stages of fracture stimulation.

After completion of the drilling phase on the Stuckey-Upchurch well, the rig was moved back to the Force Area in Madison County to commence the drilling of the Crow A-1 (74.2% WI) well, also targeting the Woodbine. The well is currently drilling at a depth of 9,140 feet, with drilling and completion operations expected to be completed by mid-September. Crimson expects this rig to stay active in the Madison and Grimes area for the remainder of the year.

Buda formation

As previously disclosed in June, Crimson successfully drilled the Beeler #2H (50% WI), its first well targeting the Buda formation in Dimmit County, Texas. The well was drilled to a total measured depth of 11,013 feet, including an approximate 3,700 foot lateral, was completed naturally without fracture stimulation, and commenced production at an initial rate of 859 boepd (89% oil). The well averaged a gross rate of 693 Boepd for its first 83 days of production.

Crimson has spud its second well in the area, the Beeler #3H (50% WI), and is currently drilling at a depth of 3,245 feet with drilling and completion operations expected to be completed in early September. Crimson expects this rig to remain active in the area for the rest of the year.

Crimson is very encouraged about the Buda potential, and views this area as another opportunity for oil and liquids growth. The Beeler #2H is located in Crimson’s Booth-Tortuga Area where the Company currently has approximately 10,140 gross acres.

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and six month periods ended June 30, 2013 and 2012:

        Three Months Ended Six Months Ended June 30, June 30, Total Volumes Sold: 2013     2012   % 2013     2012   % Crude oil (barrels) 253,457 197,185 29 % 406,499 355,818 14 % Natural gas liquids (barrels) 108,182 82,520 31 % 189,905 145,056 31 % Natural gas (Mcf) 1,855,336 2,001,086 -7 % 3,679,888 4,165,211 -12 % Natural gas equivalents (Mcfe) 4,025,170 3,679,316 9 % 7,258,312 7,170,455 1 %   Daily Sales Volumes: Crude oil (barrels) 2,785 2,167 29 % 2,246 1,955 15 % Natural gas liquids (barrels) 1,189 907 31 % 1,049 797 32 % Natural gas (Mcf) 20,388 21,990 -7 % 20,331 22,886 -11 % Natural gas equivalents (Mcfe) 44,233 40,432 9 % 40,101 39,398 2 %   Average sales prices (before hedging): Oil $ 101.84 $ 106.09 -4 % $ 103.60 $ 106.72 -3 % NGLs 28.25 35.95 -21 % 26.62 39.24 -32 % Gas 3.99 2.03 97 % 3.61 2.30 57 % Mcfe $ 9.01 $ 7.60 19 % 8.33 $ 7.43 12 %   Average sales price (after hedging): Oil $ 104.22 $ 109.06 -4 % $ 104.57 $ 107.92 -3 % NGLs 28.25 35.95 -21 % 26.62 39.24 -32 % Gas 3.95 3.02 31 % 3.62 3.15 15 % Mcfe $ 9.14 $ 8.30 10 % $ 8.39 $ 7.98 5 %   Selected Costs ($ per Mcfe): Lease operating expenses $ 0.82 $ 0.98 -16 % $ 0.90 $ 1.15 -22 % Production and ad valorem taxes $ 0.59 $ (0.68 )

na

$ 0.56 $ (0.15 )

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Depreciation and depletion expense $ 4.62 $ 3.99 16 % $ 4.33 $ 4.06 7 % General and administrative expense - Total $ 1.70 $ 1.23 38 % $ 1.54 $ 1.30 19 % General and administrative expense - Cash $ 1.53 $ 1.06 44 % $ 1.35 $ 1.13 20 % Interest $ 1.57 $ 1.69 -7 % $ 1.74 $ 1.74 0 %   Adjusted EBITDAX (1) $ 24,910,809 $ 25,480,011 -2 % $ 40,411,612 $ 41,775,064 -3 %   Capital expenditures Leasehold acquisitions 1,431,327 3,233,538 2,199,693 3,991,213 Exploratory (1,176 ) (183,474 ) 65,569 9,749,336 Development 17,851,195 24,543,078 28,183,498 46,528,191 Other 0   19,717   0 19,717   $ 19,281,346   $ 27,612,859   $ 30,448,760 $ 60,288,457     Weighted Average Shares Outstanding Basic 44,681,434 44,134,330 44,536,281 44,055,639 Diluted 44,995,267 44,992,883 44,536,281 44,484,917

(1) Adjusted EBITDAX is a non-GAAP financial measure. See below for a reconciliation to net income (loss).

         

CRIMSON EXPLORATION INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

  June 30, December 31, 2013 2012

ASSETS

Accounts receivable $ 13,924,071 $ 11,726,078 Current mark to market value of derivatives 2,084,643 1,892,744 Other current assets 791,323 844,495 Deferred tax asset (current and non-current) 54,418,105 52,171,316 Net property and equipment 298,445,132 300,827,480 Other non-current assets 1,534,715 1,158,276   TOTAL ASSETS $ 371,197,989 $ 368,620,389

LIABILITIES AND STOCKHOLDERS' EQUITY

Current mark to market value of derivatives $

-

$

-

Other current liabilities 54,198,373 38,685,288 Long-term debt, net of current portion 229,926,282 239,368,865 Other non-current liabilities 10,302,362 10,724,119 Total stockholders’ equity 76,770,972 79,842,117   TOTAL LIABILITIES & STOCKHOLDERS’ EQUITY $ 371,197,989 $ 368,620,389        

CRIMSON EXPLORATION INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

  Three Months Ended June 30, Six Months Ended June 30, 2013   2012 2013   2012   OPERATING REVENUES Crude oil sales $ 26,415,041 $ 21,505,766 $ 42,508,437 $ 38,398,380 Natural gas sales 7,326,514 6,051,551 13,329,189 13,120,665 Natural gas liquids sales 3,056,063 2,966,694 5,054,926 5,691,545

Total operating revenues

36,797,618 30,524,011 60,892,552 57,210,590   OPERATING EXPENSES Lease operating expenses 3,294,735 3,603,046 6,556,862 8,240,431 Production and ad valorem taxes 2,362,788 (2,488,997 ) 4,051,530 (1,080,256 ) Exploration expenses 185,649 48,895 303,130 349,591 Depreciation, depletion and amortization 18,612,302 14,675,882 31,452,022 29,137,944 Impairment of oil and gas properties 827,677 806,067 1,645,415 1,482,541 General and administrative 6,849,167 4,525,720 11,163,501 9,297,177 Gain on sale of assets (4,975 )

-

(11,359 ) (8,900 ) Total operating expenses 32,127,343 21,170,613 55,161,101 47,418,528   INCOME FROM OPERATIONS 4,670,275 9,353,398 5,731,451 9,792,062   OTHER INCOME (EXPENSE) Interest expense (6,325,864 ) (6,212,806 ) (12,609,601 ) (12,457,988 ) Other income and financing cost (131,814 ) (103,544 ) (251,216 ) (346,287 ) Unrealized gain on derivative instruments 2,643,221 3,037,733 760,231 2,512,100 Total other income (expense) (3,814,457 ) (3,278,617 ) (12,100,586 ) (10,292,175 )   INCOME (LOSS) BEFORE INCOME TAXES 855,818 6,074,781 (6,369,135 ) (500,113 )   Income tax (expense) benefit (317,499 ) (2,163,962 ) 2,176,055 11,847   NET INCOME (LOSS) $ 538,319 $ 3,910,819 $ (4,193,080 ) $ (488,266 )  

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, amortization and exploration expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under the credit agreements representing our senior credit facility and our second lien credit facility.

We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreements. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding, and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
• the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
• our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
• the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX and Adjusted EBITDAX are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of EBITDAX and Adjusted EBITDAX in this release is appropriate. However, when evaluating our results, you should not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss). EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

The following table reconciles net income to EBITDAX and Adjusted EBITDAX for the periods presented:

        Three Months Ended Six Months Ended June 30, June 30, 2013     2012 2013     2012   Net income (loss) $ 538,319 $ 3,910,819 $ (4,193,080 ) $ (488,266 ) Interest expense 6,325,864 6,212,806 12,609,601 12,457,988

Income tax expense (benefit)

317,499 2,163,962 (2,176,055 ) (11,847 ) Depreciation & amortization 18,612,302 14,675,882 31,452,022 29,137,944 Exploration expenses 185,649   48,895   303,130   349,591   EBITDAX 25,979,633 27,012,364 37,995,618 41,445,410   Unrealized loss (gain) on derivative inst. (2,643,221 ) (3,037,733 ) (760,231 ) (2,512,100 ) Non-cash equity-based compensation charges 687,731 639,710 1,350,276 1,172,021 Impairment and abandonment of oil and gas properties 827,677 806,067 1,645,415 1,482,541 Amortization of deferred finance costs 63,964 59,603 191,893 196,092 (Gain) loss on sale of assets (4,975 )

-

  (11,359 ) (8,900 ) Adjusted EBITDAX 24,910,809 25,480,011 40,411,612 41,775,064   Merger transaction costs 1,069,976

-

1,069,976

-

Severance tax refund

-

  (4,032,898

)

 

-

  (4,032,898 ) Adjusted EBITDAX, exclusive of special items $ 25,980,785   $ 21,447,113   $ 41,481,588   $ 37,742,166    

Updated Guidance for Third Quarter 2013

The Company is providing the following updated guidance for the third calendar quarter of 2013.

          Production volumes      

40,000 - 42,000

    Lease operating expenses ($M) $3,600 - $4,000   Production and ad valorem taxes 7% of actual prices   Cash G&A ($M) (1) $3,600 - $4,000   DD&A rate $4.60 - $4.85 per mcfe  

(1) Exclusive of merger related costs

 

Teleconference Call

Crimson management will hold a conference call to discuss the information described in this press release on Thursday, August 8, 2013 at 10:30am CDT. Those interested in participating in the earnings conference call may do so by calling the following phone number: 800-723-6575, (International 785-830-1997) and entering the following participation code 7789867. A replay of the call will be available from Thursday, August 8, 2013 at 1:30pm CDT through Thursday, August 15, 2013 at 1:30pm CDT by dialing toll free 888-203-1112, (International 719-457-0820) and asking for replay ID code 7789867.

Crimson Exploration is a Houston, TX-based independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. The Company currently owns approximately 95,000 net acres onshore in Texas, Louisiana, Colorado and Mississippi. The Company refers to its four corporate areas as (i) Southeast Texas, focusing on the Woodbine, Eagle Ford and Georgetown formations, (ii) South Texas, focusing on the Eagle Ford and Buda formations, (iii) East Texas, focusing on the Haynesville, Mid-Bossier and James Lime formations, and (iv) Rockies and Other, focusing on the Niobrara and D&J Sands formations. The Company’s strategy is to continue to increase crude oil and liquids-rich reserves and production from an extensive inventory of drilling prospects, de-risk unproved prospects in core operating areas, and opportunistically grow reserves through acquisitions complementary to its existing asset base.

Additional information on Crimson Exploration Inc. is available on the Company's website at http://crimsonexploration.com.

This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”) and applicable securities laws. Such statements include those concerning Crimson’s strategic plans, expectations and objectives for future operations. All statements included in this press release that address activities, events or developments that Crimson expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions Crimson made based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Crimson’s control. Statements regarding future production, revenue, cash flow operating results, leverage, drilling rigs operating, drilling locations, funding, derivative transactions, pricing, operating costs and capital spending, tax rates, and descriptions of our development plans are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, commodity price changes, inflation or lack of availability of goods and services, environmental risks, the proximity to and capacity of transportation facilities, the timing of planned capital expenditures, uncertainties in estimating reserves and forecasting production results, operating and drilling risks, regulatory changes and the potential lack of capital resources. All forward-looking statements are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K for the year ended December 31, 2012, and subsequent filings for a further discussion of these risks. Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.