PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT

(In thousands)

(Unaudited)

(1) RSUs defined in Note 9.

See Notes to Condensed Consolidated Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

See Notes to Condensed Consolidated Financial Statements.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q.  The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”).  These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.  All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future.  These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances.  Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of our Annual Report on Form 10-K for the year ended December 31, 2018 and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We assume no obligation, nor do we intend to update these forward-looking statements.  Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico.  We have grown through acquisitions, exploration and development and hold working interests in 47 offshore fields in federal and state waters (45 producing and two fields capable of producing).  As of June 30, 2019, we have under lease approximately 710,000 gross acres (440,000 net acres) spanning across the Outer Continental Shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 490,000 gross acres on the conventional shelf and approximately 220,000 gross acres in the deepwater (water depths in excess of 500 feet).  A majority of our daily production is derived from wells we operate.  Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy VI, LLC, a Delaware limited liability company and through our proportionately consolidated interests in Monza, as described in more detail in Financial Statements– Note 4 – Joint Venture Drilling Program under Part I, Item 1 in this Form 10-Q.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our crude oil, NGLs and natural gas production and the prices that we receive for such production.  Our production volumes for the six months ended June 30, 2019 were comprised of 51.1% crude oil and condensate, 9.2% NGLs and 39.7% natural gas, determined on a barrel of oil equivalent (“Boe”) using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel of crude oil, condensate or NGLs.  The conversion ratio does not assume price equivalency, and the price per one Boe for crude oil, NGLs and natural gas has differed significantly in the past.  For the six months ended June 30, 2019, revenues from the sale of crude oil and NGLs made up 82.5% of our total revenues compared to 81.9% for the six months ended June 30, 2018.  For the six months ended June 30, 2019, our combined total production expressed in equivalent volumes was 8.3% lower than for the six months ended June 30, 2018, with natural gas having the largest decline.  For the six months ended June 30, 2019, our total revenues were 11.6% lower than the six months ended June 30, 2018 primarily due to lower production and lower realized prices for crude oil, NGLs and natural gas.  See Results of Operations – Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018 in this Item 2 for additional information.

Our operating results are strongly influenced by the price of the commodities that we produce and sell.  The price of those commodities is affected by both domestic and international factors, including domestic production.  During the six months ended June 30, 2019, our average realized crude oil price was $61.96 per barrel.  This is a decrease from our average realized crude oil price of $64.93 per barrel, or 4.6%, for the six months ended June 30, 2018 and a decrease from our average realized crude oil price of $65.62 per barrel, or 5.6%, for the year 2018.  Our average realized prices of NGLs and natural gas for the six months ended June 30, 2019 were lower than the average realized prices for the six months ended June 30, 2018 by 29.8% and 3.8%, respectively.

Our average realized crude oil sales price differs from the WTI benchmark average crude price primarily due to premiums or discounts, crude oil quality adjustments, volume weighting (collectively referred to as differentials) and other factors.  Crude oil quality adjustments can vary significantly by field.  All of our crude oil is produced offshore in the Gulf of Mexico and is characterized as Poseidon, Light Louisiana Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others.  WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors.  Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past.  The monthly average differentials of WTI versus Poseidon, LLS and HLS for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 improved by approximately $4.00 per barrel for these types of crude oils.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel.  For the six months ended June 30, 2019 compared to the six months ended June 30, 2018, average prices for domestic ethane decreased by 15% and average domestic propane prices decreased by 30% as measured using a price index for Mount Belvieu.  The average price for other domestic NGLs components ranged from decreases of 20% to 33% for the six months ended June 30, 2019 year-over-year.  We believe the change in prices for NGLs is mostly a function of the change in crude oil prices combined with changes in propane supply and demand.

According to Baker Hughes, the number of working rigs drilling for oil and natural gas on land in the U.S. as of the end of June 28, 2019 was lower than a year ago for land based rigs (a decrease of 86 rigs, or 8%), and higher in the Gulf of Mexico (an increase of seven rigs or 37%).  The oil rig count as of June 28, 2019 and June 29, 2018 was 793 and 858, respectively.  The U.S. natural gas rig count as of June 28, 2019 and June 29, 2018 was 173 and 187, respectively.  In the Gulf of Mexico, the number of working rigs was 26 rigs (24 oil rigs and two natural gas rigs) as of June 28, 2019 and 19 rigs (15 oil rigs and three natural gas rigs) as of June 29, 2018.  During the three months ended June 30, 2019, we had four rigs running, which represents approximately 15% of the active rigs in the Gulf of Mexico.

On June 26, 2019, we entered into a purchase and sale agreement with ExxonMobil Corporation to acquire their interests in and operatorship of oil and gas producing properties in the eastern region of the GOM offshore Alabama and a related processing facility for $200 million, subject to customary post-effective date adjustments for an effective date of January 1, 2019.  The acquisition will be funded from cash on hand and borrowings under the Credit Agreement at closing date.  The transaction includes nine GOM offshore producing fields and an onshore treating facility that are adjacent to existing properties owned and operated by us.  The acquisition is expected to close on or about August 30, 2019.  As of the effective date of the acquisition, the properties had approximately 74 million Boe of net proved reserves, of which 99% were proved developed producing reserves and 22% of the proved net reserves are from liquids, based on October 15, 2018 NYMEX Henry Hub gas and NYMEX WTI oil prices.  For the first quarter of 2019, the average production of the properties being acquired was approximately 19,800 net Boe per day.     

Our capital expenditure forecast for 2019 excluding the above acquisition, other potential acquisitions and ARO is estimated to be approximately $125 to $155 million composed of select shelf and deepwater projects most of which, assuming success, would be placed on production within a few months after completion.  The forecast also incorporates our capital spending relating to the JV Drilling Program (net to our interest).  Our 2019 plans also include spending approximately $23 million for ARO.  Based upon current price and production expectations for 2019, we believe that our cash flows from operating activities, cash on hand and borrowing availability under the Credit Agreement will be sufficient to fund our operations through year-end 2019 and the acquisition of the ExxonMobil properties described above; however, future cash flows are subject to a number of variables and additional capital expenditures may be required to more fully develop our properties.  We are also currently evaluating various acquisition opportunities, which, if successful, may increase our capital requirements in 2019 and beyond.  We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2019 plans.  See our Annual Report on Form 10-K for the year ended December 31, 2018, for additional information.

Results of Operations

The following tables set forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

NM – not meaningful

Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2018

Revenues.  Total revenues decreased $14.9 million, or 10.0%, to $134.7 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018.  Oil revenues decreased $7.4 million, or 6.4%, NGLs revenues decreased $4.1 million, or 46.9%, natural gas revenues decreased $3.4 million, or 14.8%, and other revenues were approximately the same.  The decrease in oil revenues was attributable to a 3.3% decrease in the average realized sales price to $64.86 per barrel for the three months ended June 30, 2019 from $67.09 per barrel for the three months ended June 30, 2018 and a 3.2% decrease in sales volumes.  The decrease in NGLs revenues was attributable to a 36.3% decrease in the average realized sales price to $17.59 per barrel for the three months ended June 30, 2019 from $27.61 per barrel for the three months ended June 30, 2018 and a 16.5% decrease in sales volumes.  The decrease in natural gas revenues was attributable to a 6.4% decrease in the average realized price to $2.63 per Mcf for the three months ended June 30, 2019 from $2.81 per Mcf for the three months ended June 30, 2018 and a 9.0% decrease in sales volumes.  Overall, production volumes decreased 6.7% on a Boe basis.  The largest production increases for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 were from our Ship Shoal 349 (Mahogany) field, Fairway field and Viosca Knoll 734 field.  Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to maintenance issues at certain platforms and pipelines.  Our estimate of deferred production for the three months ended June 30, 2019 was approximately 4,900 Boe per day as compared to 4,600 Boe per day for the three months ended June 30, 2018, which comprises 12% of the production volume variance between the two periods. 

Revenues from oil and NGLs as a percent of our total revenues were 84.5% for the three months ended June 30, 2019 compared to 83.8% for the three months ended June 30, 2018.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 27.1% for the three months ended June 30, 2019 compared to 41.2% for the three months ended June 30, 2018.

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $4.8 million, or 13.4%, to $40.3 million for the three months ended June 30, 2019 compared to the three months ended June 30, 2018.  On a component basis, base lease operating expenses increased $2.0 million and facilities maintenance expense increased $3.5 million, partially offset by a decrease in workover expenses of $0.7 million.  Base lease operating expenses increased primarily due to lower charges to joint interest partners at our Mississippi Canyon 243 (Matterhorn) field, which are recorded as credits to expense.  In addition, base lease operating expenses increased at our Green Canyon 859 (Heidelberg) field, which was acquired in April 2018, and a credit related to settlement of a joint-venture audit recorded during the three months ended June 30, 2018.  The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Mahogany field.  The decrease in workover expense was primarily due to lower project expenses at our Mahogany field, which were partially offset by higher project expenses incurred at other fields.

Gathering and transportation.  Gathering and transportation expenses increased $2.1 million to $7.1 million for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 primarily related to rate changes from certain third-party pipelines.

Depreciation, depletion, amortization and accretion (“DD&A”).  DD&A, which includes accretion for ARO, increased to $11.94 per Boe for the three months ended June 30, 2019 from $11.63 per Boe for the three months ended June 30, 2018.  On a nominal basis, DD&A decreased to $38.1 million (or 4.2%) for the three months ended June 30, 2019 from $39.8 million for the three months ended June 30, 2018.   DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

General and administrative expenses (“G&A”).  G&A was $13.3 million for the three months ended June 30, 2019, decreasing 6.3% from $14.2 million for the three months ended June 30, 2018.  The decrease was primarily due to increased charges (credits) to counterparties related to joint interest arrangements, lower expenses related to surety bonds and lower incentive compensation expenses.  G&A on a per Boe basis was $4.18 per Boe for the three months ended June 30, 2019 compared to $4.16 per Boe for the three months ended June 30, 2018.

Derivative (gain) loss.  The three months ended June 30, 2019 reflects a $1.8 million derivative gain primarily due to decreased crude oil future pricing used to value our derivative contracts at June 30, 2019 as compared to March 31, 2019, which increased the estimated fair value of our open crude oil contracts between the two measurement dates.  For the three months ended June 30, 2018, we recorded a net loss of $6.2 million from derivative contracts.

Interest expense, net.  Interest expense, net, was $12.2 million and $11.8 million for the three months ended June 30, 2019 and 2018, respectively.  During the three months ended June 30, 2019, we accrued interest income of $4.0 million related to income tax refunds as we received confirmation from the IRS that our refund filings have been approved for payment.   During the three months ended June 30, 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under Accounting Standard Codification Topic 470-60, Troubled Debt Restructuring (“ASC 470-60”), which lowered reported interest expense for the three months ended June 30, 2018 and affects the comparability.

Income tax (benefit) expense.  Our income tax benefit for the three months ended June 30, 2019 was $11.7 million and our income tax expense for the three months ended June 30, 2018 was $0.1 million.  During the three months ended June 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, which resulted in a net tax benefit for the three months ended June 30, 2019.  Immaterial deferred income tax expense was recorded for the three months ended June 30, 2018 due to dollar-for-dollar offsets by our valuation allowance.  Our effective tax rate using book pre-tax income was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.  As of June 30, 2019, our valuation allowance was $121.8 million.  We continually evaluate the need to maintain a valuation allowance on our deferred tax assets.  Any future reduction of a portion or all of the valuation allowance would result in a non-cash income tax benefit in the period the decision occurs.  See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2018

Revenues.  Total revenues decreased $33.0 million, or 11.6%, to $250.8 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018.  Oil revenues decreased $18.0 million, or 8.4%, NGLs revenues decreased $7.3 million, or 39.7%, natural gas revenues decreased $7.4 million, or 15.2%, and other revenues decreased $0.3 million.  The decrease in oil revenues was attributable to a 4.6% decrease in the average realized sales price to $61.96 per barrel for the six months ended June 30, 2019 from $64.93 per barrel for the six months ended June 30, 2018 and a 4.1% decrease in sales volumes.  The decrease in NGLs revenues was attributable to a 29.8% decrease in the average realized sales price to $19.36 per barrel for the six months ended June 30, 2019 from $27.57 per barrel for the six months ended June 30, 2018 and a 14.1% decrease in sales volumes.  The decrease in natural gas revenues was attributable to a 3.8% decrease in the average realized price to $2.81 per Mcf for the six months ended June 30, 2019 from $2.92 per Mcf for the six months ended June 30, 2018 and a 11.8% decrease in sales volumes.  Overall, production volumes decreased 8.3% on a Boe basis.  The largest production increases for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 were from our Mahogany field, Ship Shoal 028 field, Ship Shoal 032 field, Fairway field and Heidelberg field, which was acquired in April 2018.  Offsetting the production increases were production decreases primarily from natural production declines and from increases in downtime, with the largest amounts related to maintenance issues at certain platforms and pipelines.  Our estimate of deferred production for the six months ended June 30, 2019 was approximately 6,000 Boe per day as compared to 4,400 Boe per day for the six months ended June 30, 2018, which comprises 52% of the production volume variance between the two periods.  

Revenues from oil and NGLs as a percent of our total revenues were 82.5% for the six months ended June 30, 2019 compared to 81.9% for the six months ended June 30, 2018.  Our average realized NGLs sales price as a percent of our average realized crude oil sales price decreased to 31.2% for the six months ended June 30, 2019 compared to 42.5% for the six months ended June 30, 2018.

Lease operating expenses.  Lease operating expenses, which include base lease operating expenses, workovers, and facilities maintenance, increased $11.4 million, or 15.7%, to $83.8 million in the six months ended June 30, 2019 compared to the six months ended June 30, 2018.  On a component basis, base lease operating expenses increased $3.4 million, facilities maintenance expense increased $6.4 million and workover expenses increased $1.6 million.  Base lease operating expenses increased primarily due to the addition of the Heidelberg field, acquired in April 2018, which had an increase in base lease operating expense of $2.3 million.  In addition, base lease operating expenses increased due to lower charges to joint interest partners at our Matterhorn field, which are recorded as credits to expense, and a credit related to settlement of a joint-venture audit recorded during the six months ended June 30, 2018.  The increase in facility maintenance expenses involved numerous fields and projects with the largest increase at our Mahogany field.  The increase in workover expense was primarily due to 2019 projects at our Mahogany field. 

Gathering and transportation.  Gathering and transportation expenses increased $3.5 million to $13.5 million for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily related to rate changes from certain third-party pipelines which became effective during the three months ended June 30, 2019.

Depreciation, depletion, amortization and accretion.  DD&A, which includes accretion for ARO, increased to $11.61 per Boe for the six months ended June 30, 2019 from $11.54 per Boe for the six months ended June 30, 2018.  On a nominal basis, DD&A decreased to $71.8 million (or 7.7%) for the six months ended June 30, 2019 from $77.8 million for the six months ended June 30, 2018.  DD&A on a nominal basis decreased primarily due to lower production.  Other factors affecting the DD&A rate are capital expenditures, sales of assets, future development costs and changes in proved reserves volumes.

General and administrative expenses.  G&A was $27.4 million for the six months ended June 30, 2019, decreasing 6.2% from $29.3 million for the six months ended June 30, 2018.  The decrease was primarily due to lower expenses related to surety bonds and lower incentive compensation expenses.  G&A on a per Boe basis was $4.43 per Boe for the six months ended June 30, 2019 compared to $4.34 per Boe for the six months ended June 30, 2018.

Derivative loss.  The six months ended June 30, 2019 reflects a $47.1 million derivative loss primarily due to increased crude oil future pricing used to value our derivative contracts at June 30, 2019 as compared to December 31, 2018, which decreased the estimated fair value of our open crude oil contracts between the two measurement dates.  For the six months ended June 30, 2018, we recorded a net loss of $6.2 million from derivative contracts.

Interest expense, net.  Interest expense, net, was $28.5 million and $22.7 million for the six months ended June 30, 2019 and 2018, respectively.  During the six months ended June 30, 2019, we accrued interest income of $4.0 million related to income tax refunds as we received confirmation from the IRS that our refund filings have been approved for payment.  During the six months ended June 30, 2018, a portion of our interest was recorded as offsets to carrying value adjustments on the balance sheet under ASC 470-60, which lowered reported interest expense and affects the comparability.

Income tax (benefit) expense.  Our income tax benefit for the six months ended June 30, 2019 was $11.5 million and our income tax expense for the six months ended June 30, 2018 was $0.2 million.  During the six months ended June 30, 2019, we reversed a liability related to an uncertain tax position that was effectively settled with the IRS, which resulted in a net tax benefit for the six months ended June 30, 2019.  Immaterial deferred income tax expense was recorded for the six months ended June 30, 2018 due to dollar-for-dollar offsets by our valuation allowance.  Our effective tax rate using book pre-tax income was not meaningful for either period.  For both periods, adjustments in the valuation allowance primarily offset changes in net deferred tax assets.  See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.  

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our AROs.  We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank borrowings and expect to continue to do so in the future.

Credit Agreement.  On October 18, 2018, we entered into the Credit Agreement, which matures on October 18, 2022.  As of June 30, 2019, we had $21.0 million borrowings outstanding under the Credit Agreement and $7.2 million of letters of credit issued under the Credit Agreement.  During the six months ended June 30, 2019, we did not have any additional borrowings or repayments under the Credit Agreement.  Availability under our Credit Agreement as of June 30, 2019 was $221.8 million.  As noted in the Overview section of this Item, the funding of the pending oil and gas property acquisition from ExxonMobil will be from cash on hand and borrowings under the Credit Agreement.

Availability under our Credit Agreement is subject to a semi-annual redetermination of our borrowing base, which was initially set at $250.0 million and has not changed.  The next redetermination is to be completed by November 15, 2019.  Any redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our Credit Agreement.  The Credit Agreement is secured and collateralized by substantially all of our oil and natural gas properties and certain personal property.

We currently have six lenders under our Credit Agreement, with commitments ranging from $25.0 million to $62.5 million for the current borrowing base.  While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.  See Financial Statements – Note 2 –Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

Senior Second Lien Notes.  As of June 30, 2019, we had outstanding $625.0 million principal of Senior Second Lien Notes with an interest rate of 9.75% per annum that matures on November 1, 2023.  The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements – Note 2 –Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information.

Debt Covenants.  The Credit Agreement and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Credit Agreement and the indenture related to the Senior Second Lien Notes.  We were in compliance with all applicable covenants of the Credit Agreement and the Senior Second Lien Notes indenture as of June 30, 2019.

Bureau of Ocean Energy Management ("BOEM") Matters.  As of the filing date of this Form 10-Q, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations.  We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive requests or demands in the future for financial assurances from the BOEM.

Surety Bond Collateral.  Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and materially impact our liquidity.  In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion.  No additional demands were made to us by sureties during 2019 as of the filing date of this Form 10-Q and we currently do not have surety bond collateral outstanding.

The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Cash Flow and Working Capital.  Net cash provided by operating activities for the six months ended June 30, 2019 and 2018 was $106.3 million and $115.2 million, respectively.  Our combined average realized sales price per Boe decreased by 3.7% for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, which caused total revenues to decrease $15.7 million.  Production volumes decreased by 8.3% primarily from increases in downtime, which caused revenues to decrease by $17.0 million.  In addition, operating expenses impacting operating cash flows increased by $14.1 million primarily for workover and facility projects.

Other items affecting operating cash flows was an increase of $18.5 million for the six months ended June 30, 2019 in the balance of cash advances received from joint venture partners, primarily from Monza, compared to a decrease of $3.8 million for the six months ended June 30, 2018.  ARO settlements were $9.5 million lower between the two periods and cash derivative receipts, net, increased $13.9 million between the two periods primarily due to derivative oil contracts.  Working capital items accounted for the balance of the change in net cash provided by operating activities.

Net cash used in investing activities for the six months ended June 30, 2019 and 2018 was $73.1 million and $77.8 million, respectively, which represents our investments in oil and gas properties and equipment.  Our capital expenditures for the six months ended June 30, 2019 were split fairly evenly for investments in the deep waters of the Gulf of Mexico and on the conventional shelf of the Gulf of Mexico.  During the six months ended June 30, 2019, we made a deposit of $10.0 million related to the pending oil and gas property acquisition from ExxonMobil described in the Overview section of this Item and there were no material acquisitions or asset sales in the period.  During the six months ended June 30, 2018, the purchase of the interest in the Heidelberg field was consummated for $16.6 million.

Net cash used by financing activities for the six months ended June 30, 2019 and 2018 was $0.8 million and $7.1 million, respectively.  The net cash used for the six months ended June 30, 2018 was primarily for interest payments on certain debt reported as financing activities under ASC 470-60.

Derivative Financial Instruments.  From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas.  During 2018, we entered into derivative contracts for crude oil and natural gas for a portion of our future production.  See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.  

Insurance Coverage.  We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.  With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering all of our higher valued properties, and $150 million for all other properties subject to a retention of $30.0 million. Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.  The operational and named windstorm coverages are effective for one year beginning June 1, 2019.  Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, 2019 and provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.  With respect to the Oil Spill Financial Responsibility requirement under the Oil Pollution Act of 1990, we are required to evidence $150.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount.

Although we were able to renew our general and excess liability policies effective on May 1, 2019, and our Energy Package effective on June 1, 2019, our insurers may not continue to offer this type and level of coverage to us in the future, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurers will not pay our claims.  We do not carry business interruption insurance.

Capital Expenditures.  The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of crude oil, NGLs and natural gas, acquisition opportunities, available liquidity and the results of our exploration and development activities.  During the six months ended June 30, 2018, we received reimbursement of capital expenditures from Monza for projects in the JV Drilling Program, some of which had incurred costs during 2017.  These reimbursements related to 2017 are reported in a separate line in the table below.  The following table presents our capital expenditures for exploration, development and other leasehold costs (in thousands):

The following table presents our exploration and development capital expenditures geographically in the Gulf of Mexico (in thousands):

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets.  The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments to report payments related to capital expenditures.

Our capital expenditures for the six months ended June 30, 2019 were financed by cash flow from operations and cash on hand.

During the six months ended June 30, 2019, we completed the Virgo A-13 well, which began producing during March 2019 and the South Timbalier 320 A-3 well, which began producing in July 2019.  Both of these wells are in the JV Drilling Program.  We did not drill any dry holes during the six months ended June 30, 2019.  During the six months ended June 30, 2018, we completed two wells. 

Exploration/Development Activities. As of July 15, 2019, we were drilling on the Ship Shoal 028 #41 well and were performing completion operations on the MC 800 S02 well.  Both of these wells are in the JV Drilling Program.

Offshore Lease Awards.  During the six months ended June 30, 2019, we were successful in acquiring leases on 15 blocks (eight deepwater and seven shallow water) from the Gulf of Mexico Lease Sale 252 held by the BOEM on March 20, 2019, and these leases have been officially assigned to us.  These 15 blocks cover approximately 73,500 acres and we paid approximately $3.5 million for all of the awarded leases combined, which reflects a 100% working interest in the acreage.  

Capital Expenditure Forecast.  Our 2019 capital expenditure forecast is estimated to be approximately $125 to 155 million, which excludes the pending transaction for the Exxon Mobil properties described in the Overview section of this Item, any additional potential acquisitions and ARO.  The forecast incorporates the shared investments in certain wells included in the JV Drilling Program.  We strive to maintain flexibility in our capital expenditure projects and if prices remain at current levels or improve, we may increase our investments.

Income Taxes.  As of June 30, 2019, we had current income taxes receivable of $54.1 million and accrued $4.0 million of related interest income, which is expected to be received in the third quarter of 2019.  For 2019, we do not expect to make any significant income tax payments.  See Financial Statements – Note 10 –Income Taxes under Part I, Item 1 of this Form 10-Q for additional information.

Asset Retirement Obligations.  Each quarter, we review and revise our ARO estimates.  Our ARO as of June 30, 2019 and December 31, 2018 were $323.3 million and $310.1 million, respectively.  Our plans include spending approximately $23 million in 2019 for ARO compared to $28.6 million spent on ARO in 2018.  As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates.  See Risk Factors, under Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 for additional information.

Contractual Obligations.  Updated information on certain contractual obligations is provided in Financial Statements – Note 2 – Long-Term Debt, Note 5 – Asset Retirement Obligations and Note 7 – Oil and Gas Property Acquisition under Part I, Item 1 of this Form 10-Q.  As of June 30, 2019, drilling rig commitments, excluding ARO drilling rig commitments, were approximately $10.2 million, which was approximately the same as the amount as of December 31, 2018.  Except for scheduled utilization, other contractual obligations as of June 30, 2019 did not change materially from the disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018.

Critical Accounting Policies

Our significant accounting policies are summarized in Financial Statements and Supplementary Data under Part II, Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2018. See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1 of this Form 10-Q for additional information.

Recent Accounting Pronouncements

See Financial Statements - Note 1 - Basis of Presentation under Part 1, Item 1, of this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the six months ended June 30, 2019 did not change materially from the disclosures in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2018.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2018.

Commodity Price Risk.  Our revenues, profitability and future rate of growth substantially depend upon market prices of crude oil, NGLs and natural gas, which fluctuate widely.  Crude oil, NGLs and natural gas price declines have adversely affected our revenues, net cash provided by operating activities and profitability in the past and could have impacts on our business in the future.  During 2018, we entered into derivative crude oil contracts related to a portion of our estimated future production.  We historically have not designated our commodity derivatives as hedging instruments and any future derivative commodity contracts are not expected to be designated as hedging instruments.  Use of these contracts may reduce the effects of volatile crude oil and natural gas prices, but they also may limit future income from favorable price movements. See Financial Statements – Note 6 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk.  As of June 30, 2019, we had $21.0 million borrowings outstanding under our Credit Agreement and were subject to the variable London Interbank Offered Rate and the Applicable Margin.  We did not have any derivative instruments related to interest rates.

Item 4. Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based on that evaluation, our CEO and CFO have each concluded that as of June 30, 2019, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended June 30, 2019, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

See Financial Statements – Note 12 – Contingencies and Note 13  – Subsequent Event , under Part I Item 1 of this Form 10-Q for information on various legal proceedings to which we are a party or our properties are subject.

Item 1A. Risk Factors

Investors should carefully consider the risk factors included under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management.

The potential effects of crude oil prices are discussed under Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018 and also discussed in the Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Overview section of this Form 10-Q.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2018.

Item 6. Exhibits

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 1, 2019.

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