Management’s Discussion and Analysis contains “forward-looking statements” that are based on management’s current expectations, estimates and projections about our business operations. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of numerous factors, including the known material factors set forth in “Risk Factors.” You should read the following discussion and analysis together with our Combined Financial Statements and the notes to those statements included elsewhere in this information statement.
The Separation and Spin-Off
On July 30, 2013, Oil States announced that its board of directors had authorized management to pursue the spin-off of its Accommodations business into a standalone, publicly traded company. The proposed spin-off is expected to be executed through a tax free distribution to Oil States shareholders. Oil States intends to distribute, on a pro rata basis, shares of Civeo common stock to the Oil States shareholders as of the record date of the spin-off. Upon completion of the spin-off, Oil States and Civeo will each be independent, publicly traded companies and will have separate public ownership, boards of directors and management. The completion of the spin-off will be subject to, among other things, final approval of the Oil States board of directors and the receipt of a private letter ruling from the IRS which affirms the tax free nature of the spin- off.
The combined financial statements included in this information statement have been prepared in connection with the spin-off and reflect the combined results of operations, financial position and cash flows of the Accommodations Business of Oil States as if it had operated on a stand-alone basis for all periods presented. All material intercompany accounts within Civeo have been eliminated. Historically, Oil States has provided services to and funded certain expenses for Civeo. The combined statements of income reflect expense allocations for these functions, which include: (1) finance, legal, risk management, tax, treasury, information technology, human resources and certain other shared services; (2) certain employee benefits; and (3) share-based compensation. The combined statements do not include all of the actual expenses that would have been incurred had Civeo been an independent, stand-alone company during the periods presented.
Macroeconomic Environment
We provide workforce accommodation to the natural resource industry in Canada, Australia and the U.S. Demand for our services can be attributed to two phases of our customers’ projects: (1) the development or construction phase and (2) the operations or production phase. Initial demand for our services is driven by our customers’ capital spending programs related to the construction and development of oil sands and coal mines and associated infrastructure as well as the exploration for oil and natural gas. Long term demand for our services is driven by continued development and expansion of natural resource production and operation of oil sands refining facilities. Industry capital spending programs are generally based on the long-term outlook for commodity prices, economic growth and estimates of resource production. As a result, demand for our products and services is largely sensitive to expected commodity prices, principally related to crude oil, met coal and, to a lesser extent, natural gas.
In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Pricing for WCS is driven by several factors. A significant factor affecting WCS pricing is the underlying price for WTI. As WTI prices have improved over the past few years with the global economic recovery, WCS prices have also improved. Another significant factor affecting WCS pricing has been transportation. Historically, WCS has traded at a discount to WTI, or “WCS Basis Differential,” due to transportation costs and limited capacity to move growing Canadian crude oil production to U.S. refineries. Depending on the extent of pipeline capacity availability, the WCS Basis Differential has varied. With the increase in global oil prices and increased transportation capacity from the oil sands region due to rail and barge alternatives, the absolute price of WCS has increased and the WCS Basis Differential has decreased. WCS prices in 2013 averaged $73.58 per barrel compared to $71.80 per barrel in 2012. However, the WCS Basis Differential widened substantially from below $15 per barrel to $18 per barrel as of April 30, 2014, as production increased and demand from U.S. refineries declined due to maintenance requirements. Should the price of WTI decline or the WCS Basis Differential widen further, our oil sands customers’ may delay additional investments or reduce their spending in the oil sands region.
Given the historical volatility of WTI crude prices and the WCS Basis Differential, there remains a risk that prices in the oil sands could deteriorate going forward due to slowing growth rates in China, fiscal and financial uncertainty in the U.S. and various European countries, potentially negative effects on economic growth in the U.S. due to automatic government spending cuts and a prolonged level of relatively high unemployment in the U.S. and other advanced economies. However, if the global supply of oil and global inventory levels were to decrease due to government instability in a major oil-producing nation and energy demand continues to increase in countries such as China, India and the U.S., we could see continued and/or additional increases in WTI crude prices which coupled with an improvement in takeaway capacity from the oil sands could improve WCS pricing. This, in turn, could lead to our oil sands customers increasing their investments in oil sands production. Conversely, if WCS crude prices continue to experience a significant discount to WTI crude, our oil sands customers’ may have an incentive to delay additional investments in their oil sands assets.
Natural gas prices and WTI crude oil pricing, discussed above, have an impact on the demand for our U.S. accommodations. Prices for natural gas in the United States improved during 2013 and early 2014, largely due to above average storage withdrawals in response to colder than normal weather, continued elevated demand for natural gas for electric power generation, lower net imports from Canada and higher industrial demand. However, natural gas prices continue to be weak relative to prices experienced in 2006 through 2008 due to the rise in production from unconventional natural gas resources in North America, specifically onshore shale production, resulting from the broad application of horizontal drilling and hydraulic fracturing techniques. Any increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, could constrain prices for natural gas for an extended period and result in fewer rigs drilling for gas in the near-term. Lower rig counts typically impact our mobile fleet in the United States. However, SAGD development utilizes natural gas and lower natural gas prices could have a positive impact on this activity in Canada. Natural gas prices traded at approximately $4.82 per Mcf as of April 30, 2014.
Our Australian villages in the Bowen Basin primarily serve coal mines in that region. Met coal pricing and growth in production in the region is influenced by levels of steel production. Because Chinese steel production has been growing at a slower pace than that experienced in 2010 and early 2011, Chinese demand for imported steel inputs such as met coal and iron ore decreased during 2013 compared to 2012. Met coal prices have decreased materially from over $200/metric ton at the beginning of 2012 to approximately $150/metric ton at the end of 2013. Depressed met coal prices have led to the implementation of cost control measures by our customers, some coal mine closures and delays in the start-up of new coal mining projects in Australia. A continued depressed met coal price will impact our customers’ future capital spending programs.
Recent WTI crude, WCS crude, Queensland hard coking coal and natural gas pricing trends are as follows:
Average Price (1)
Quarter ended WTI Crude
(per bbl) WCS Crude (per bbl)
Hard Coking Coal (per ton) Henry Hub Natural Gas (per mcf) 12/31/2013 $ 97.50 $ 66.34 $ 143.76 $ 3.85 9/30/2013 105.83 83.10 142.21 3.55 6/30/2013 94.05 77.48 149.94 4.02 3/31/2013 94.33 66.86 167.71 3.49 12/31/2012 88.01 61.34 156.79 3.40 9/30/2012 92.17 76.75 187.88 2.88 6/30/2012 93.38 73.53 216.49 2.29 3/31/2012 102.85 75.82 212.20 2.44 12/31/2011 94.03 81.56 236.69 3.32 9/30/2011 89.71 75.05 296.24 4.12 6/30/2011 102.51 84.72 315.74 4.37
(1) Source: WTI crude and natural gas prices from U.S. Energy Information Administration (EIA), and WCS crude prices and Queensland hard coking coal index from Bloomberg.
Overview
Demand for our services is primarily tied to the long-term outlook for crude oil and met coal prices. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the U.S., Canada, Australia and in other markets.
Generally, our customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of ten years to in excess of thirty years. Consequently, these investments are dependent on those customers’ longer-term view of commodity demand and prices. Oil sands development and production activity has increased over the past several years and has had a positive impact on our Canadian business. Recent announcements of new and expanded oil sands projects can create the opportunity to extend existing accommodations contracts and incremental contracts for us in Canada. For example, in the third quarter of 2012, we were awarded a ten-year contract in support of future operations personnel working on the Kearl Project, one of the Canadian oil sands potentially largest mining operations. In addition, several major and national oil companies have announced acquisitions and joint ventures to develop oil sands leases or other acquisitions of oil sands exposure that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. However, given the WCS discount to WTI, several oil sands customers have announced the deferral of new oil sands projects, which could negatively affect our ability to expand our oil sands room count or our occupancy levels in the near term.
We expanded our Australian room capacity in 2012 and 2013 to meet increasing demand, notably in the Bowen Basin in Queensland and in the Gunnedah Basin in New South Wales to support coal production, and in Western Australia to support LNG and other energy-related projects. In early 2013, a confluence of low met coal pricing, additional carbon and mining taxes on our Australian customers and several years of cost inflation caused several of our customers to delay or reduce their growth plans. This has negatively affected our ability to expand our room count and to maintain or increase occupancy levels. It has also caused one of our customers to renegotiate contracts to reduce their forward room commitments beginning in March 2014 in return for termination compensation beginning in March 2014.
Exchange rates between the U.S. dollar and the Canadian dollar and between the U.S. dollar and the Australian dollar influence our U.S. reported financial results. Our business has historically derived a vast majority of its revenues and operating income in Canada and Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the year ended December 31, 2012, average U.S. dollar and Canadian and Australian dollar exchange rates were comparable with a less than 1% change over average exchange rates in 2011. However during 2013, particularly at year end, we saw a strengthening U.S. dollar compared to both the Canadian and Australian dollars. During 2013, the Canadian and Australian dollars weakened 7% and 15%, respectively, relative to the U.S. dollar. A strong U.S. dollar is generally viewed positively for our Australian customers as they typically receive U.S. dollar denominated payment for their commodities with expenses denominated in Australian dollars.
While global demand for oil and natural gas are significant factors influencing our business generally, certain other factors also influence our business, such as the pace of worldwide economic growth.
We continue to monitor the global economy, the demand for crude oil, met coal and natural gas and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. Our capital expenditures in 2013 totaled $292 million compared to $314 million in 2012.
Consolidated Results of Operations (in millions)
Twelve Months Ended December 31,
Variance 2013 vs. 2012 Variance 2012 vs. 2011 2013 2012 $ % 2011 $ % Revenues Canada ... $ 710.5 $ 717.2 $ (6.7) (1%) $ 579.9 $ 137.3 24% Australia ... 255.5 276.2 (20.7) (7%) 197.1 79.1 40% United States ... 75.1 115.5 (40.4) (35%) 87.7 27.8 32% Total ... $ 1,041.1 $ 1,108.9 $ (67.8) (6%) $ 864.7 $ 244.2 28% Cost of sales Canada ... $ 399.0 $ 386.9 $ 12.1 3% $ 334.4 $ 52.5 16% Australia ... 96.1 104.6 (8.5) (8%) 74.0 30.6 41% United States ... 54.5 60.9 (6.4) (11%) 48.0 12.9 27% Total ... $ 549.6 $ 552.4 $ (2.8) (1%) $ 456.4 $ 96.0 21% Gross profit Canada ... $ 311.5 $ 330.3 $ (18.8) (6%) $ 245.5 $ 84.8 35% Australia ... 159.4 171.6 (12.2) (7%) 123.1 48.5 39% United States ... 20.6 54.6 (34.0) (62%) 39.7 14.9 38% Total ... $ 491.5 $ 556.5 $ (65.0) (12%) $ 408.3 $ 148.2 36% Operating income Canada ... $ 190.8 $ 226.4 $ (35.6) (16%) $ 162.3 $ 64.1 39% Australia ... 75.2 99.2 (24.0) (24%) 63.2 36.0 57% United States ... (1.9) 31.4 (33.3) (106%) 19.6 11.8 60% Other... (4.6) (4.1) (0.5) 12% (2.9) (1.2) 41% Total ... $ 259.5 $ 352.9 $ (93.4) (26%) $ 242.2 $ 110.7 46%
YEAR ENDED DECEMBER 31, 2013 COMPARED TO YEAR ENDED DECEMBER 31, 2012
We reported net income attributable to the Accommodations business for the year ended December 31, 2013 of $181.9 million. This result compares to net income attributable to the Accommodations business of $244.7 million reported for the year ended December 31, 2012, which included a gain of $17.9 million from a favorable contract settlement reported in our U.S. accommodations segment.
Revenues. Revenues decreased $67.8 million, or 6%, in 2013 compared to 2012.
Our Canadian segment reported revenues in 2013 that were $6.7 million, or 1%, lower than those in 2012. The decrease in Canadian accommodations revenue primarily resulted from a 9% reduction in Revenue per Available Room (RevPAR) in our lodges. The RevPAR reduction was due to a 3% weakening of the Canadian dollar relative to the U.S. dollar as well as lower contracted rates at our Wapasu Lodge and modestly reduced occupancy at our Beaver River and Athabasca Lodges. Those declines were partially offset by an 8% increase in the average number of available lodge rooms.
Our Australian segment reported revenues in 2013 that were $20.7 million, or 7%, below 2012. Increased revenue at our Coppabella and Narrabri villages due to room additions as well as contributions from our new Karratha village were offset by lower occupancy at our Middlemount and Calliope villages. Additionally, the exchange rate between the U.S. dollar and Australian dollar resulted in a 7% year over year reduction in revenue. Within Australia, the average number of available rooms increased by 15%, but unfavorable exchange rate movements and reduced occupancy at Calliope and Middlemount contributed to a decrease in RevPAR of 19%.