Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Hi-Crush Inc. | a33115-earningsrelease8xk.htm |
| EX-99.1 - EXHIBIT 99.1 - Hi-Crush Inc. | exhibit991-earningsrelease.htm |
1ST QUARTER 2015 RESULTS MAY 6, 2015
Forward Looking Statements Some of the information included herein may contain forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations and may contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “could,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no expected results of operations or financial condition or other forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in Hi-Crush Partners LP’s (“Hi-Crush”) reports filed with the Securities and Exchange Commission (“SEC”), including those described under Item 1A, “Risk Factors” of Hi-Crush’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and any subsequently filed Quarterly Report on Form 10-Q. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the risk factors in our reports filed with the SEC or the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include: the volume of frac sand we are able to sell; the price at which we are able to sell frac sand; the outcome of any litigation, claims or assessments, including unasserted claims; changes in the price and availability of natural gas or electricity; changes in prevailing economic conditions; and difficulty collecting receivables. All forward- looking statements are expressly qualified in their entirety by the foregoing cautionary statements. Hi-Crush’s forward-looking statements speak only as of the date made and Hi-Crush undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise. 2
Drop in Rig Count Felt in Q1 2015 3 (1) Represents distributions declared during the quarter. • 2015 activity decline in perspective against strong growth from prior year • Decline in frac sand demand in Q1 2015 due to steep decline in rig count • Focused on customer relationships to navigate current conditions and grow long-term market share • Long-term fundamentals regarding sand demand remain strong Q1 2015 Q4 2014 Q1 2014 ($ in 000s, except per unit) Revenues $102,111 $130,929 $70,578 EBITDA $29,581 $44,567 $23,942 Sales volumes 1,195,343 1,481,914 898,243 Production costs per ton $16.28 $15.72 $20.66 Earnings per unit Basic $0.61 $0.85 $0.49 Diluted $0.60 $0.85 $0.49 Distributions per unit 1 $0.675 $0.675 $0.525
Balance Sheet Remains Strong 4 (1) Revolving credit facility: $130.5mm available at L+2.75% ($150mm capacity less $12.5mm of borrowings and $7.0mm of LCs); includes accordion feature to increase to $200mm. (2) Senior secured term loan: $200mm face value at L+3.75%; rated B2 and B+ by Moody's and Standard & Poor's, respectively; includes accordion feature to increase to $300mm. Leverage (as of March 31, 2015) ($ in 000s) Cash 4,913$ Revolver 12,500$ 1 Term loan 196,259 2 Other notes payable 3,676 Total debt 212,435$ Net debt 207,522$ Net debt / LTM EBITDA 1.35x
Committed to Long-Term Distribution Growth 5 • Distribution declared for Q1 2015 held flat • Annualized rate of $2.70 per unit up 12.5% over distributions of $2.40 per unit paid in 2014 — Distribution increases possible when market visibility strengthens — Expect at a minimum to maintain distribution at current level Distributions Per Unit Paid (Annualized) * * $1.90 represents the Minimum Quarterly Distribution per unit $1.90 $1.96 $2.04 $2.10 $2.30 $2.50 $2.70 $2.70 Q3 '13 Q4 '13 Q1 '14 Q2 '14 Q3 '14 Q4 '14 Q1 '15 Q2 '15
Coverage Maintained During Tough Quarter 6 • Maintaining and prudently growing distributions to unit holders are key priorities — Coverage ratio averaging 1.23x since Q1 2013, above target coverage of 1.20x • Strong coverage in prior quarters allowed for investment in organic growth with little debt (1) Actual coverage ratio was 1.0x including $0.525 per unit distribution paid on 4.25 million units issued in April 2014 (2) Excludes impact of the August 15, 2014 conversion of Class B units to common units and related distribution paid upon conversion (3) Excludes the portion of DCF allocable to the Incentive Distribution Rights held by our Sponsor (1) (2) (3) (3) (3) (3) 1.12x 1.14x 1.24x 1.38x 1.15x 1.35x 1.40x 1.31x 1.00x – 0.20x 0.40x 0.60x 0.80x 1.00x 1.20x 1.40x $0 $5 $10 $15 $20 $25 $30 $35 Q1 '13 Q2 '13 Q3 '13 Q4 '13 Q1 '14 Q2 '14 Q3 '14 Q4 '14 Q1 '15 $ i n M ill io n s Declared Distributions (Total $/Q) - LHS Coverage Ratio - RHS
Industry Backdrop
Fundamentals Still Support Long-Term Demand “We also continue to make progress on our frac optimization learnings, where we are now consistently placing our laterals in the portion of the reservoir where the best rock properties occur, and we are placing more sand per foot of lateral while controlling costs by varying the stage phasing of the completions.” Q1 2015 Earnings Call “As operators drop horizontal rigs, they drill longer and longer laterals, with some operators now consistently drilling 8,000 foot to 10,000 foot laterals. In addition, the number of frac stages increased, and the spacing between stages decreased, and sand concentrations went up. All of this led to higher production.” Q1 2015 Earnings Call • E&P operators are using fracture stimulation techniques, such as longer laterals, increased frac stages per well, increased proppant per stage, and infill drilling to drive well performance and sand demand 8 “But for the most part, you're really just not getting the bang for the buck by using ceramic, so we're able to trim quite a bit of cost off by sticking with white sand.” Q1 2015 Earnings Call Targeting of Shale & Unconventional Reservoirs Increased Use of Horizontal Drilling More Wells per Rig Longer Laterals More Stages per Lateral Foot More Proppant per Stage Long-Term Proppant Demand
Timing & Magnitude of Recovery Remain Unclear 9 • Since the peak in U.S. land rigs, rig count has dropped for 23 consecutive weeks — Vertical rig count has decreased by 68% — Directional rig count has declined by 55% — Horizontal rig count has fallen by 49% • Competition among oilfield service providers fierce — Some pressure pumpers bidding jobs at cash costs to maintain market share — Others choosing to stack equipment to avoid wear and tear at unjustifiable margin — Increased competition decreasing supply chain visibility and contributing to logistics and production planning challenges • Growing inventory of drilled but uncompleted wells contributing to drop in proppant demand — Limited number of well capitalized operators deferring completions for better economics — Completion costs have come down, following a quicker drop in drilling expenses — Sand demand may rebound faster than rig count during recovery given backlog
Current Environment 10 • Continued supply chain improvements and market share consolidation — Oilfield service providers still seeking efficiencies through supply chain enhancements • Sand suppliers working with customers to lower all-in pricing at well head through better origin/destination matching, increased unit trains, and more in-basin services • Service providers continuing to consolidate vendors down to key partners, capable of delivery large quantities, efficiently, and on-time • Potential for refracs in early stages — Could represent an initial spike in demand when recovery begins — Operators testing results using comparable amounts of sand as original frac job • As of May 1, 2015, the U.S. land permit count increased by 225 (30%) from the prior week — May signal higher activity level in the second half of 2015
Hi-Crush Operations
Hi-Crush’s Competitive Advantages • Long-Term Contracted Cash Flow • Low-Cost Producer • Long-Lived, High Quality Reserves • Prime Portfolio of Assets • Focused Strategy • Visible Avenues to Growth 12 8 Long-Term Contracts, 4.2 Average Years Remaining >75% of Production Capacity Contracted Long-Term Northern White Frac Sand Demand Key Strategic Network in Marcellus/Utica Strong Balance Sheet Future Whitehall Drop-Down, Sponsor’s 4th Facility, Expansion of Terminal Facilities
Logistics Flexibility Critical Sandstone Formations • Access to all major North American oil and gas basins • Direct loading and unloading of unit trains • Multiple in-basin terminals across Marcellus and Utica shales, two located in Permian Basin, and one in DJ Basin1 • ~7,000 railcars under management — ~2,900 owned/leased by Hi-Crush as of March 31, 2015 • Strong relationships with multiple Class-1 and short-line railroads Sponsor’s Whitehall Facility 13 Sponsor Sand Facilities Terminal Under Development Basin Play HCLP Sand Facilities Existing Distribution Terminals (1) New Permian Basin and DJ Basin terminals expected to be operational early 2016 and late 2015, respectively.
A Strategy for the Current Market 14 • Northern White still in highest demand relative to other proppant types • Migration to in-basin sales as a way for customers to lower supply chain costs • Organic growth of distribution network • Dropdown of Sponsor’s Whitehall facility when the timing is right • Fourth facility permitted by Sponsor — Facility planned to be 3mm tons per year capacity of high-quality Northern White, including 100 mesh — Positioned to capture long-term market share during recovery
Financial Results
1st Quarter 2015 Summary 16 Three Months Ended March 31, 2015 2014(a) Revenues $ 102,111 $ 70,578 Cost of goods sold (including depreciation, depletion and amortization) 68,639 44,166 Gross profit 33,472 26,412 Operating costs and expenses: General and administrative expenses 6,218 6,425 Accretion of asset retirement obligation 83 57 Income from operations 27,171 19,930 Other income (expense): Interest expense (3,317 ) (1,410 ) Net income 23,854 18,520 Income attributable to non-controlling interest (169 ) (148 ) Net income attributable to Hi-Crush Partners LP $ 23,685 $ 18,372 Earnings per unit: Common units - basic $ 0.61 $ 0.49 Subordinated units - basic $ 0.61 $ 0.49 Common units - diluted $ 0.60 $ 0.49 Subordinated units - diluted $ 0.60 $ 0.49 (a) Financial information has been recast to include the financial position and results attributable to Hi -Crush Augusta LLC.
1st Quarter 2015 Summary 17 Three Months Ended March 31, (in thousands) 2015 2014 Reconciliation of distributable cash flow to net income: Net income $ 23,854 $ 18,520 Depreciation and depletion expense 1,677 1,476 Amortization expense 733 2,536 Interest expense 3,317 1,410 EBITDA $ 29,581 $ 23,942 Less: Cash interest paid (2,905 ) (1,272 ) Less: Income attributable to non-controlling interest (169 ) (148 ) Less: Maintenance and replacement capital expenditures, including accrual for reserve replacement (1) (1,259 ) (969 ) Add: Accretion of asset retirement obligation 83 57 Add: Unit based compensation 884 — Distributable cash flow $ 26,215 $ 21,610 Adjusted for: Distributable cash flow attributable to Hi-Crush Augusta LLC, net of intercompany eliminations, prior to the Augusta Contribution (2) — (4,188 ) Distributable cash flow attributable to Hi-Crush Partners LP 26,215 17,422 Less: Distributable cash flow attributable to holders of incentive distribution rights (1,311 ) — Distributable cash flow attributable to common and subordinated unitholders $ 24,904 $ 17,422 (1) Maintenance and replacement capital expenditures, including accrual for reserve replacement, were determined based on an estimated reserve replacement cost of $1.35 per ton produced and delivered during the period. Such expenditures include those associated with the replacement of equipment and sand reserves, to the extent that such expenditures are made to maintain our long-term operating capacity. The amount presented does not represent an actual reserve account or requirement to spend the capital. (2) The Partnership's historical financial information has been recast to consolidate Augusta for all periods presented. For purposes of calculating distributable cash flow attributable to Hi-Crush Partners LP, the Partnership excludes the incremental amount of recasted distributable cash flow earned during the periods prior to the acquisition by the Partnership on April 28, 2014 of substantially all of the remaining equity interests in Hi- Crush Augusta LLC (the "Augusta Contribution").