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HOS > SEC Filings for HOS > Form 10-Q on 9-Nov-2012All Recent SEC Filings




Quarterly Report

Item 2-Management's Discussion and Analysis of Financial Condition and Results of Operations

The following Management's Discussion and Analysis of Financial Condition and Results of Operations should be read together with our unaudited consolidated financial statements and notes to unaudited consolidated financial statements in this Quarterly Report on Form 10-Q and our audited financial statements and notes thereto included in our Annual Report on Form 10-K as of and for the year ended December 31, 2011. This discussion contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements. See "Forward Looking Statements" for additional discussion regarding risks associated with forward-looking statements. In this Quarterly Report on Form 10-Q, "company," "we," "us," "our" or like terms refer to Hornbeck Offshore Services, Inc. and its subsidiaries, except as otherwise indicated. Please refer to Item 5 - Other Information for a glossary of terms used throughout this Quarterly Report on Form 10-Q.

In this Quarterly Report on Form 10-Q, we rely on and refer to information regarding our industry from the EIA and IHS-Petrodata, Inc. These organizations are not affiliated with us and are not aware of and have not consented to being named in this Quarterly Report on Form 10-Q. We believe this information is reliable. In addition, in many cases we have made statements in this Quarterly Report on Form 10-Q regarding our industry and our position in the industry based on our experience in the industry and our own evaluation of market conditions.


Our Upstream Segment

The OSV market continues to expand globally. Offshore exploration and production activities are increasingly focused on deep wells (as defined by total well depth rather than water depth), whether on the Outer Continental Shelf or in the deepwater or ultra-deepwater. These types of wells require high-specification equipment and have resulted in an on-going newbuild cycle for drilling rigs and for high-spec OSVs. As a result of the projected deepwater drilling activity levels worldwide, there were 84 floating rigs under construction or on order on October 31, 2012 and, as of that date, there were options outstanding to build 31 additional floating rigs and 10 units announced but yet to be contracted with shipyards. In addition, on that date, there were 89 high-spec jack-up rigs under construction or on order worldwide, and there were options outstanding to build 32 additional high-spec jack-up rigs and three units announced but not yet contracted with shipyards. Each drilling rig working on deep-well projects typically requires more than one OSV to service it. The number of OSVs required per rig is dependent on many factors, including the type of activity being undertaken and the location of the rig. For example, based on the historical data for the number of floating rigs and OSVs working, we believe that two to four OSVs per rig are required in the GoM and even more OSVs may be necessary per rig in Brazil where greater logistical challenges result in longer vessel turnaround times to service drill sites. Typically, during the initial drilling stage, more OSVs are required to supply drilling mud, drill pipe and other materials than at later stages of the drilling cycle. In addition, more OSVs are generally required the farther a drilling rig is located from shore. Under normal weather conditions, the transit time to deepwater drilling rigs in the GoM and Brazil can typically range from six to 24 hours for a new generation vessel. Moreover, in Brazil, transit times for a new generation vessel to some

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of the newer, more logistically remote deepwater drilling rig locations are more appropriately measured in days, not hours. In addition to drilling rig support, deepwater and ultra-deepwater exploration and production activities will result in the expansion of other specialty-service offerings for our vessels. These markets include subsea construction support, installation, IRM work, and life-of-field services, which include well-stimulation, workovers and decommissioning.

Presently, our oilfield service operations are conducted in three primary geographic regions comprised of the GoM, Brazil and Mexico. Descriptions of these three regions are included below.

GoM. The GoM continues to be considered a world-class basin by exploration and production companies. The EIA estimates that the GoM contains 68 billion barrels of recoverable oil equivalent utilizing existing technologies. According to data compiled by IHS-Petrodata, the number of floating rigs available in the GoM region is currently 43, which has increased from the pre-Macondo level of 34, because the eight floaters that either left the region or were stacked and the three floaters that have been stacked or are currently being rebuilt, have since been replaced by 20 similar or more advanced rigs. During 2011 and early 2012, a gradual improvement in the number of incremental deepwater well permits issued per month occurred, albeit through surges of activity followed by sharp declines. This sporadic permitting activity has continued throughout 2012 and we anticipate that the pace of permit issuance will be uneven for some time to come. Of the 43 rigs available in the GoM, 32 were actively drilling as of October 31, 2012. For the five pre-Macondo years of 2005 through 2009, the historical average level of floating rigs actively drilling was 29 rigs with a peak of 35 rigs. We expect that floating rig growth in the GoM will continue to be driven by demand in the deepwater and ultra-deepwater, primarily in water depths greater than 3,000 feet.

Improvement in dayrates and utilization for our high-spec vessels has continued through the third quarter of 2012. Leading-edge spot market OSV dayrates in the GoM for our 240 and 265 class DP-2 equipment remain in the $30,000 to $36,000 range. Whether these rates can be sustained will depend, among other things, on the future pace of permitting in the GoM. Fleetwide effective, or utilization-adjusted, dayrates for our new generation OSVs increased about $3,300, or roughly 21%, from $15,772 for the third quarter of 2011 to $19,072 for the third quarter of 2012. During the quarter ended September 30, 2012, we had an average stacked new generation OSV fleet of 2.1 vessels compared to 6.3 vessels for the same period in 2011. As of October 31, 2012, we had two DP-1 new generation OSVs stacked. We have elected to keep these vessels out-of-service due to the uneven demand for this equipment. During the third quarter we mobilized four DP-1 vessels from Brazil to the GoM. We determined not to renew contracts for these vessels with Petrobras due to high operating costs in Brazil and dayrates that were not commensurate with alternative markets for such vessels. Since their return to the GoM, these vessels have experienced low utilization due to planned drydockings and soft market conditions for DP-1 vessels in the GoM. The Company has selected these vessels to be converted into 240 class DP-2 vessels, which we believe will enable them to compete more effectively in the GoM, where DP-2 vessels are emerging as the industry standard for deepwater operations. We expect that these DP-1 vessels will experience additional softness prior to their shipyard periods which will commence on various dates in December 2012. The shipyard conversion period for each vessel is expected to last approximately 127 days, per vessel. Similar commercial downtime

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has been experienced in the GoM by previously stacked DP-1 vessels that have been reactivated during 2012. The Company is considering whether these vessels are candidates for conversion to DP-2.

The recent recovery in the GoM may be adversely affected by an increasing shortage of, and competition for, qualified mariners. This shortage is being exacerbated by customer and regulatory driven requirements that increase the manning levels on many vessels, including drilling units that operate in the GoM. Mariner shortages have driven up labor costs, which comprise the greatest portion of our operating costs. To address intense competition for mariners, we increased our Upstream crew wages in April 2012 by roughly $5.0 million per quarter. We expect these increased wage levels to continue into 2013 and beyond. We will also have incremental expenses due to the expansion of our fleet personnel and shoreside support staff in anticipation of the vessels that will be delivered under our OSV newbuild program #5.

Brazil. Brazil is experiencing a dramatic increase in activity related to its large deepwater and pre-salt oilfield basins. This increase in activity is driven primarily by the state-owned oil company, Petroleo Brasileiro S.A., or Petrobras, and other producers, including BP p.l.c., Chevron Corporation, Exxon Mobil Corporation, OGX Petroleo e Gas Participacoes and Royal Dutch Shell plc. Petrobras has publicly announced plans to spend approximately $128 billion on exploration and production activities from 2011 through 2015 and has stated that its offshore supply vessel needs could increase from approximately 290 in 2010 to nearly 480 in 2015. Brazilian operators plan to add three new floating rigs by the end of 2013. Since the beginning of 2010, we have increased our presence in Brazil from zero to a high of 14 vessels. As of October 31, 2012, we had eight vessels working in Brazil under long-term contracts for Petrobras. We expect to bid on additional contracts in Brazil. However, high operating costs as well as regulatory complexity and bureaucratic inefficiency are impacting our ability to generate operating margins commensurate with those we have historically generated in the GoM. Moreover, Petrobras is the single largest consumer of our services in Brazil and, for 2011, the Company overall. As is typical with large state-owned national oil companies, contracts with Petrobras are onerous and contain multiple provisions that allow Petrobras to impose penalties and deduct payments for performance issues even if we disagree with the basis of those penalties or deductions. Petrobras has exercised these kinds of measures in our contract and we expect that we will continue to confront similar issues with Petrobras going forward. In addition to regulatory complexity and the inherent difficulties associated with the Petrobras contracting regime, there is an acute shortage of mariners in Brazil, which we are required by law to employ on our vessels. This shortage is a significant contributor to escalating costs in Brazil and could present a barrier to our growth in that market.

Mexico. The primary customer in the Mexican market is the state-owned oil company, PEMEX. Production from the Cantarell field, which according to the EIA is PEMEX's largest offshore oilfield, has declined from approximately 2.14 million barrels per day to 500,000 barrels per day. In 2010, 54% of Mexico's total crude oil production came from the Cantarell field and the Ku-Maloob-Zaap field, both of which are located in the Bay of Campeche. In its July 2011 Outlook, PEMEX highlighted that 60% of its prospective resources, or 29.5 billion barrels of oil equivalent, are in the deepwater Gulf of Mexico. However, in order to develop this resource, PEMEX will likely need to tap the expertise of non-Mexican international oil companies. Under Article 27 of the Mexican constitution, private persons or companies (other

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than the state-owned PEMEX) are not allowed to carry out the exploration for petroleum, and solid, liquid, or gaseous hydrocarbons. As a result, while we believe that Mexico could develop into a large market for deepwater activity, we do not expect this to occur until the Mexican government has found a solution to their constitutional constraints. We believe that this situation may be improved by the recent election of President Peņa Nieto, who campaigned on constitutional reform to reinvigorate the Mexican oil industry. Currently, there are four floating rigs and 32 jack-up rigs drilling offshore Mexico. PEMEX has announced plans to add another floating rig and three more high-spec jack-up rigs during the remainder of 2012. We began working in Mexico in 2002 and currently have seven vessels working there under long-term contracts. We will continue to actively bid additional vessels into Mexico as tenders are issued by PEMEX.

Market conditions. As of October 31, 2012, we had 72% of our new generation OSV vessel-days contracted for the fourth quarter of 2012, with 30 vessels contracted beyond the end of the year. Our forward OSV contract coverage for 2013 currently stands at 35%. Our MPSV contract coverage for the fourth quarter of 2012 has also increased as a result of the improving market conditions in the GoM. On the strength of two long-term contracts awarded to our MPSVs during 2011 and recent spot market activity, MPSV contract coverage for the remainder of 2012 and 2013 is currently 85% and 40%, respectively.

A sustained market recovery will depend upon several factors outside of our control including 1) the ability of operators and drilling contractors to comply with the new regulatory rules; 2) the pace at which regulators approve plans and permit applications required by operators to drill; 3) the content of additional as yet unpromulgated rules that are expected to be issued; 4) the outcome of pending litigation brought by environmental groups challenging recent exploration plans approved by the DOI and 5) general economic conditions.

All of our current Upstream vessels are qualified under the Jones Act to engage in U.S. coastwise trade, except for five foreign-flagged new generation OSVs, two foreign-flagged well stimulation vessels and two foreign-flagged MPSVs. As of September 30, 2012, our 49 active new generation OSVs and four MPSVs were operating in domestic and international areas as noted in the following table:

                       Operating Areas
                       GoM                              30
                       Other U.S. coastlines (1)         5


                       Brazil                            8
                       Mexico                            8
                       Middle East                       2


                       Total Upstream Vessels (2)       53

(1) Includes vessels that are currently supporting the military.

(2) Excluded from this table are two of our new generation OSVs and one conventional OSV that were stacked as of September 30, 2012. The remaining stacked new generation OSVs are expected to remain inactive until there is sustainable demand for these vessels.

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Our Downstream Segment

As of September 30, 2012, our Downstream fleet was comprised of nine double-hulled tank barges and 14 ocean-going tugs, five of which are older, lower-horsepower tugs that are stacked. The prolonged weakness in the overall economy, which has impacted our Downstream segment since 2008, continues to adversely impact demand for Downstream equipment to some extent. Although Downstream results for the third quarter have improved from the prior year, recent dayrate trends are well below the Downstream dayrates that existed from 2006 to 2008. Driven by demand in the GoM resulting from the Eagle Ford shale trend, we outfitted three additional vessels with vapor-recovery systems during the second quarter of 2012 to allow them to work in the trans-Gulf crude oil trade. We feel as if these developments will have a positive impact on our Downstream vessels operating in the GoM during the fourth quarter of 2012 and first half of 2013. With the protracted weak demand for tugs and tank barges coupled with the expansion of our Upstream fleet, we expect our Downstream segment to continue to represent a much smaller portion of our consolidated operating results compared to historical trends.

Critical Accounting Estimates

This Management's Discussion and Analysis of Financial Condition and Results of Operations discusses our unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. generally accepted accounting principles, or GAAP. In other circumstances, we are required to make estimates, judgments and assumptions that we believe are reasonable based on available information. We base our estimates and judgments on historical experience and various other factors that we believe are reasonable based upon the information available. Actual results may differ from these estimates under different assumptions and conditions. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011.

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Results of Operations

The tables below set forth, by segment, the average dayrates, utilization rates and effective dayrates for our vessels and the average number and size of vessels owned during the periods indicated. These new generation OSVs and tank barges generate a substantial portion of our revenues and operating profit. Excluded from the OSV information below are the results of operations for our MPSVs, conventional vessels, our shore-base facility, and vessel management services. The Company does not provide average or effective dayrates for its new generation MPSVs as such amounts are skewed by highly variable customer-required costs-of-sales associated with ancillary equipment and services, such as ROVs and cranes. These costs-of-sales are typically recovered through higher dayrates charged to the customer. Nevertheless, due to the fact that each of our MPSVs have a workload capacity and significantly higher income generating potential than each of the Company's new generation OSVs, the utilization and dayrate levels of our MPSVs could have a significant impact on our results of operations. For this reason, our consolidated operating results, on a period-to-period basis, are disproportionately impacted by the level of dayrates and utilization achieved by our four MPSVs.

                                              Three Months Ended                Nine Months Ended
                                                September 30,                     September 30,
                                            2012             2011             2012             2011
New Generation Offshore Supply
Average number of new generation OSVs
(1)                                            51.0             51.0             51.0             51.0
Average number of active new
generation OSVs (2)                            48.9             44.7             47.9             40.5
Average new generation OSV fleet
capacity (DWT)                              128,190          128,190          128,190          128,190
Average new generation vessel
capacity (DWT)                                2,514            2,514            2,514            2,514
Average new generation OSV
utilization rate (3)                           79.5 %           75.3 %           82.9 %           67.5 %
Effective new generation OSV
utilization rate (4)                           82.9 %           85.9 %           88.3 %           84.9 %
Average new generation OSV dayrate
(5)                                       $  23,990        $  20,945        $  23,248        $  20,812
Effective dayrate (6)                     $  19,072        $  15,772        $  19,273        $  14,048
Double-hulled tank barges:
Average number of tank barges (7)               9.0              9.0              9.0              9.0
Average fleet capacity (barrels)            884,621          884,621          884,621          884,621
Average barge capacity (barrels)             98,291           98,291           98,291           98,291
Average utilization rate (3)                   93.4 %           92.0 %           84.5 %           88.3 %
Average dayrate (8)                       $  16,626        $  18,222        $  16,742        $  17,351
Effective dayrate (6)                     $  15,529        $  16,764        $  14,147        $  15,321

(1) We owned 51 new generation OSVs as of September 30, 2012. Excluded from this data is one stacked conventional OSV that we consider to be a non-core asset. Also excluded from this data are four MPSVs owned and operated by the Company.

(2) In response to weak market conditions, we elected to stack certain of our new generation OSVs on various dates in 2009 and 2010. Based on improved market conditions, we had re-activated 13 new generation OSVs as of September 30, 2012. The two remaining stacked new generation OSVs are expected to remain inactive until there is sustainable demand for these vessels. Active new generation OSVs represent vessels that are immediately available for service during each respective period.

(3) Utilization rates are average rates based on a 365-day year. Vessels are considered utilized when they are generating revenues.

(4) Effective utilization rate is based on a denominator comprised only of vessel-days available for service by the active fleet, which excludes the impact of stacked vessel days.

(5) Average dayrates represent average revenue per day, which includes charter hire, crewing services and net brokerage revenues, based on the number of days during the period that the OSVs generated revenue.

(6) Effective dayrate represents the average dayrate multiplied by the average utilization rate.

(7) Other operating data for tugs and tank barges reflects our active Downstream fleet of nine double-hulled barges and nine ocean-going tugs. We also own five older, lower-horsepower tugs, which we consider to be non-core assets and are marketed for sale. We previously owned a fleet of single-hulled tank barges; however, all of those vessels have been sold as they were also considered non-core assets.

(8) Average dayrates represent average revenue per day, including time charters, brokerage revenue, revenues generated on a per-barrel-transported basis, demurrage, shipdocking and fuel surcharge revenue, based on the number of days during the period that the tank barges generated revenue. For purposes of brokerage arrangements, this calculation excludes that portion of revenue that is equal to the cost paid by customers of in-chartering third-party equipment.

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Non-GAAP Financial Measures

We disclose and discuss EBITDA as a non-GAAP financial measure in our public releases, including quarterly earnings releases, investor conference calls and other filings with the Securities and Exchange Commission. We define EBITDA as earnings (net income) before interest, income taxes, depreciation and amortization. Our measure of EBITDA may not be comparable to similarly titled measures presented by other companies. Other companies may calculate EBITDA differently than we do, which may limit its usefulness as comparative measure.

We view EBITDA primarily as a liquidity measure and, as such, we believe that the GAAP financial measure most directly comparable to this measure is cash flows provided by operating activities. Because EBITDA is not a measure of financial performance calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.

EBITDA is widely used by investors and other users of our financial statements as a supplemental financial measure that, when viewed with our GAAP results and the accompanying reconciliation, we believe provides additional information that is useful to gain an understanding of the factors and trends affecting our ability to service debt, pay deferred taxes and fund drydocking charges and other maintenance capital expenditures. We also believe the disclosure of EBITDA helps investors meaningfully evaluate and compare our cash flow generating capacity from quarter to quarter and year to year.

EBITDA is also a financial metric used by management (i) as a supplemental internal measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; (ii) as a significant criteria for annual incentive cash compensation paid to our executive officers and bonuses paid to other shore-based employees; (iii) to compare to the EBITDA of other companies when evaluating potential acquisitions; and (iv) to assess our ability to service existing fixed charges and incur additional indebtedness.

The following table provides the detailed components of EBITDA as we define that term for the three and nine months ended September 30, 2012 and 2011, respectively (in thousands).

                                      Three Months Ended            Nine Months Ended
                                        September 30,                 September 30,
                                     2012           2011           2012           2011
    Components of EBITDA:
    Net income (loss)              $   7,401      $    (741 )    $  25,722      $ (16,802 )
    Interest expense, net
    Debt obligations                  14,697         15,062         42,971         44,976
    Interest income                     (524 )         (156 )       (1,538 )         (575 )

    Total interest, net               14,173         14,906         41,433         44,401

    Income tax expense (benefit)       4,713            445         15,879         (8,360 )
    Depreciation                      15,124         15,230         45,377         45,759
    Amortization                       6,688          5,155         19,712         15,320

    EBITDA                         $  48,099      $  34,995      $ 148,123      $  80,318

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The following table reconciles EBITDA to cash flows provided by operating activities for the three and nine months ended September 30, 2012 and 2011, respectively (in thousands).

                                              Three Months Ended               Nine Months Ended
                                                 September 30,                   September 30,
                                             2012            2011             2012            2011
EBITDA Reconciliation to GAAP:
EBITDA                                     $  48,099       $  34,995       $  148,123       $  80,318
Cash paid for deferred drydocking
charges                                      (12,700 )        (6,098 )        (32,445 )       (16,478 )
Cash paid for interest                       (10,378 )       (10,633 )        (28,755 )       (32,481 )
Cash paid for income taxes                      (235 )          (334 )           (964 )          (833 )
Changes in working capital                    20,545         (21,553 )          8,303         (17,051 )
. . .
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