Oil & Gas Reports
Q1 INDUSTRY UPDATE
1. Uinta Basin Crude production is expected to exceed Salt Lake City capacity later in 2018
2. Andeavor Logistics to acquire the Wamsutter Pipeline System
3. External rail markets for Uinta Basin Crude being considered in Price, UT and Rifle, CO
4. Axia Energy II announces acquisition of 25% of EP Energy
5. Lessons learned from the DAPL protests by Native Americans
1. UINTA BASIN CRUDE PRODUCTION IS EXPECTED TO EXCEED SALT LAKE CITY CAPACITY LATER IN 2018
- The Uinta Basin is within 20,000bpd of the capacity of the Salt Lake City refiners.
- Once the Basin exceeds this production amount, differentials of Uinta Basin Waxy Crude will increase unless another refining or storage market is identified.
- Uinta Basin producers continue to look for an external market for Black and Yellow Wax Crude.
- Recent transactions by well-funded private equity firms buying existing producing assets and advances in completion techniques are creating a surge in the production of the Uinta Basin resource.
- Producers in the Uinta Basin are closely monitoring the refiners’ capacity constraints in Salt Lake City; production in excess of 90,000bpd will be subject to additional discounting.
- Salt Lake City is currently applying a $3 discount to WTI combined with a $5 trucking cost, implying a price of WTI -$8.00 pricing today; discounts have been as high as $24.00/bbl in 2014.
- The external market for Black and Yellow Wax Crude will cost between $10 and $15/bbl; therefore, Uinta Basin production in excess of 90,000bpd will be priced between WTI less $10 to $15 ($10/bbl for unit train and $15/bbl for manifest rail transportation) and $0 for the discount.
2. ANDEAVOR LOGISTICS TO ACQUIRE THE WAMSUTTER PIPELINE SYSTEM
- Andeavor Logistics (NYSE:ANDX), a $10.4 billion market capitalization midstream company based in San Antonio, Texas, is set to acquire the Wamsutter Pipeline System from Plains All American Pipeline (NYSE:PAA), a Houston, Texas-based pipeline operator, for $180 million, funded by its credit line.
- The Wamsutter Pipeline System is a strategic 575-mile crude oil pipeline that travels from Wyoming to Salt Lake City refineries.
- Andeavor Logistics is the midstream company for Tesoro, which has a refinery in Salt Lake City; ANDX paid nine times the $20 million of EBITDA for the Wamsutter Pipeline.
- With synergies alone, Andeavor Logistics expects the assets to generate $24 million in annual EBITDA.
- Further growth in EBITDA could come from maintenance projects to increase the crude oil flow and allow Andeavor more capacity to access lower cost and quality Canadian Crude.
- Andeavor views this acquisition as a strategic asset that would keep the Salt Lake City refineries supplied with crude.
- The main trunk pipeline originates in Ft. Laramie, Wyoming, connects at Guernsey, Wyoming and extends west to Wamsutter, Wyoming, where it divides:
- The northern segment continues west, eventually delivering to Salt Lake City.
- The southern segment extends south to Rangely, Colorado where it connects to a ChevronTexaco pipeline that serves Salt Lake City.
- The original asset was built in 1939, with additional pipelines and facilities added in 1991.
- The Pipeline is an interstate and intrastate common carrier crude oil pipeline.
- The entire Salt Lake City Core System consists of 913 miles of trunk pipelines, 209 miles of gathering pipelines and 29 storage tanks with approximately 1.4 million barrels of storage capacity…
Q4 INDUSTRY UPDATE
1. Water-Related Pipeline, Storage & Treatment Infrastructure is One of the Fastest-Growing Oilfield Segments in the U.S.
2. Crescent Point Announces Significant Increase to Uinta Inventory
3. LINN Energy Announces Sale of the Uinta Basin assets for $132 Million
1. WATER-RELATED PIPELINE, STORAGE & TREATMENT INFRASTRUCTURE IS ONE OF THE FASTEST-GROWING OILFIELD SEGMENTS IN THE U.S.
To complete a single two-mile horizontal well, producers or their contractors need to bring in several hundred thousand barrels of fresh, treated or brackish water. This is not an easy task in dry and dusty Oklahoma, West Texas and Utah, which is where some of the largest land-based oil reserves are located.
Each barrel of crude oil that emerges from a well requires a significant amount of water to be transported and safely disposed of or recycled. With crude production rising, an increasing number of water recycling and pipeline projects are being announced to keep pace with production growth.
Growth in water-related infrastructure is being driven by unprecedented investments in the oilfield, as producers ratchet up their planned 2018 capex. The following are drivers for the increase:
- Producers are assembling larger leaseholds in oilfields by filling in gaps so that their holdings are contiguous and are not “checkerboarded” (interspersed with leaseholds held by other producers, private land owners or Native American Indian Tribal Lands).
- Large acreage positions allow producers to drill longer horizontal wells or laterals (now often 7,500 to 10,000 feet, and sometimes longer).
- Producers have intensified the use of pressure, frac sand and water per linear foot of lateral and frac stages.
- Increasingly complex water logistics require advanced water monitoring and automation capabilities to source reliable, expandable and logistically sound fresh, brackish and recycled water
Producers and water service companies are incorporating water gathering and recycling into their field development programs to help manage sourcing and disposal costs. High-quality service providers are solving the complex logistical challenges that come with the shift to produced water recycling/reuse:
- Increased pipeline infrastructure
- Fewer fluid hauling trucks
- Increased storage/containment needs
- Increased water treatment and completion chemicals needs
- Increased automation and health and environmental safeguards
- Increased demand for monitoring solutions to ensure adequate water supply
- “Last-mile” transportation (lay-flat hose)…
Q3 INDUSTRY UPDATE
Uinta Basin Has the Resource Capacity to Rival the Permian Basin, Once a Crude Oil Pipeline is Constructed.
Midstream and Refining Continue to Perform Well in the Energy Sector.
The Uinta Basin, located in Northeast Utah, consists of 6 million acres, of which 4.5 million acres (almost 7,000 square miles) represents the footprint of the Ute Indian Tribe of the Uintah and Ouray Reservation. Ute Indians have lived in the region for over 10,000 years and the region was first visited by Spanish explorers in 1776. Boarder disputes led to the creation of the Reservation by decree signed by Abraham Lincoln in 1864. The Basin has been producing oil since the early 1950s and is now in the top 20 oil producing fields in North America, with peak production of 89,000 bpd in 2014, which represents an average annual growth rate of 13%. Current production is approximately 70,000 bpd.
Physical characteristics of Uinta Basin crude oil include:
- High-quality crude oil with an average 41-degree API gravity and low sulfur content
- Highly paraffinic crude oil (waxy crude) with a 15% wax content
- High pour-point characteristic (temperature in which the oil becomes solid), which necessitates the need to maintain the oil in a liquid transportable state above 115 degrees Fahrenheit.
Transportation issues with the Basin create a discount to West Texas Intermediate (WTI), making it difficult to maximize value as almost 100% of the crude is trucked to the Salt Lake City refining market that has capacity constraints of 90,000 bpd and sell into a smaller regional refined finished product market with no access to international markets. In April 2013, a $3 million study titled “Final Report: Uinta Basin Energy and Transportation Study” addressed the capacity limitations of transportation infrastructure over the next three decades and the economic costs associated with lost oil and gas production. The analysis indicated that $0.5 to $1.0 billion is lost each year due to the lack of take-away capacity and refining capacity connected to the Salt Lake City market. The value of Uinta Basin crude can be improved by a transporting solution that delivers the oil via rail to more competitive markets that currently have no access to the Uinta Basin Crude…
Q2 INDUSTRY UPDATE
Lessons Learned from Dakota Access Pipeline – Partner With Native Americans on Midstream Energy Projects for Best Results
Midstream Continues to Outperform Other Segments
After the Public Relations disaster between the Standing Rock Tribe and Energy Transfer Partners (NYSE:ETP), some energy infrastructure developers are looking to include Native American Tribes in the permitting, construction and operations, which may help keep a project out of the press and social media and assist in the financial performance of the asset. Without including the Native American Indians in an energy infrastructure project, development companies can follow every law, go above and beyond legal requirements, yet still encounter problems.
The Standing Rock Sioux Tribe successfully used social media when it was excluded from the permitting and financial upside of the Dakota Access Pipeline. With an amplified voice, the Standing Rock supporters could easily say things that were not founded in fact regarding the safety of crude oil transportation using pipelines. The goal was to find an audience looking to oppose the development of oil and gas reserves. Ten years ago, most of this process would have been quietly handled in state and federal courts. Today, social media platforms have become primary news and information sources for many people who trust the information without further verifying it. Social media accelerates social movements, as catchy Twitter hashtags (i.e., #NoDAPL) filled with emotion and celebrity backing go viral. Facts that go against preconceived opinions are ignored.
A better solution for energy infrastructure companies is to form strategic alliances with Tribal and Native American enterprises that allow outside capital providers and expertise to partner with the people that have unique aboriginal rights over the land and resources. These rights can be in exchange for an economic interest in the asset that could shorten the permitting and construction phases. SDR has analyzed several documents that discuss the numerous business advantages that Native American enterprises can bring to an energy infrastructure development project (see pages 3-4).2 The majority of the advantages come from 8(a) minority status contracting preferences, tax advantages and low interest debt. Under this ”win-win” scenario, Native Americans get an economic “carry” and/or the right to participate in the energy infrastructure project and they can use their unique rights to assist in the financing, permitting, construction and operation of the asset…
Q1 INDUSTRY UPDATE
Dakota Access and Keystone XL Pipelines Get Approval
Midstream Is Best Performer in the Energy Sector in Q1
The approval of the permits for construction of the Dakota Access and Keystone XL pipelines will be the first of many infrastructure projects that will be approved in order to help put more Americans to work, provide environmental benefits and create tax revenue. These projects will help lower the production costs for the development of North American natural resources, which have poor economics at the current lower energy prices.
The Keystone XL pipeline is an $8-billion project that will span 1,200 miles, connecting Alberta’s tar sands crude with pipelines and refineries on the Texas Gulf Coast that are well-suited for handling the heavy oil. The proposed Keystone XL expansion will not go the right of way of the original Keystone pipeline (see map above); instead, it will go along a shorter, more direct route through Nebraska that will allow the crude to go to storage and blending facilities in Cushing, Oklahoma and Patoka, Illinois.
Cushing and Patoka are vital trans-loading points that are connected to dozens of refiners in the Midwest and Texas Gulf Coast the use the existing interconnected pipeline systems already in place (see maps on top of page 3).
The gulf coast refiners are running at 92.5% utilization, which is an all-time high. Gulf coast refiners are maxing out their capacity to meet the dramatic growth in the demand for refined finished product. In the first quarter of 2017, refined finished product exports averaged 5.3 million bpd, which is up 1.7 million bpd from only one year ago. This represents a 47% increase…
Rocky Mountain Energy Industry Expected to Grow.
Exploration and Production Companies Breakout in 2016.
In General, Rocky Mountain Region Companies Outperform Peers.
Most likely, Houston always will be the center of the U.S. Energy Industry. But in the fourth quarter of 2016, the Rocky Mountain Region (CO, UT, NM, WY, ND, SD, MT) attracted the Headquarters of two significant players in the Energy Markets: BP America and Extraction Oil and Gas.
In this report, SDR Ventures sets the baseline for the Rocky Mountain Region’s role in the overall U.S. oil and gas landscape. The Rocky Mountain Region typically has been viewed as regional offices that close in downturns as jobs get reeled back to headquarters. This is what happened in 2015 and 2016 (and previously); however, this trend may be starting to change and a newfound attention may be placed on the region.
On October 17, Colorado-based Extraction Oil & Gas, Inc. (NASDAQ:XOG or “Extraction”) closed its initial public offering of $633 million or 33.3 million shares of its common stock at $19.00 per share. This IPO is the largest in the oil and gas industry globally since October 2014. The stock is trading near the opening price. Extraction is investing almost all of the proceeds to drilling wells in the Wattenburg Field in Colorado’s DJ Basin. The completion of the Grand Mesa Pipeline is a major factor in Extraction’s decision to raise equity because the pipeline provided sufficient off-take capacity to Cushing, OK and lowered the operating cost of the field.
In addition, on December 14, London-based BP announced that it will move its U.S. Lower 48 Headquarters from Houston to Denver in early 2018. Initially, BP expects the office to have 200 employees, ramping up to 400 employees over time. BP’s Lower 48 CEO David Lawler said that Denver emerged early in the selection process because two thirds of BP’s operated oil and natural gas production and reserves are in the Rocky Mountain corridor. BP spun its Lower 48 operations into a separate unit in 2015.
Our analysis, which begins on the next page, shows that, in general, companies that choose to be headquartered in the Rocky Mountain Region had better financial performance metrics in 2016, even though their stock price performances were mixed compared their peers. In particular, Rocky Mountain Midstream companies had significantly better performance metrics across the board and increased stock prices by over 52% in 2016, compared to 22% for the segment as a whole (see teal callout boxes on page 4). Rocky Mountain Exploration & Production (E&P) companies had a strong 2016 finish, posting a 29% Q4 stock increase, versus 17% for the segment in general (see page 3)…
A Closer Look at Extraction’s IPO
On October 17, Colorado-based Extraction Oil & Gas, Inc. (NASDAQ:XOG or “Extraction”) priced and closed its initial public offering of $633 million or 33.3 million shares of its common stock at $19.00 per share. Extraction initially was offering the shares at an estimated price range of $15.00 to $18.00. The stock continues to trade in the $21.00 to $22.00 per share range. This energy IPO is the largest IPO in the oil and gas industry globally since October 2014.
In our view, the success of the Extraction IPO is encouraging for companies in the industry that desire to raise capital to fund their growth by investing in projects with IRRs desirable to Wall Street Investors. Even though Extraction is focused on what some in the industry consider to be a “second or third-tier basin,” it has some unique dynamics set to work in its favor, most notably a lower-cost drilling environment and its proximity and commitment to the nearly complete Grand Mesa Pipeline.
The chart below shows Daily Oil Production by “year of first flow” for Adams, Arapahoe, Boulder, Larimer, Morgan and Weld Counties in Colorado, the primary counties in which Extraction operates. The increase in production and steep decline curves indicate that (assuming reasonable off-take arrangements), low-cost drilling and $50 oil production can be a profitable investment and can attract capital to this basin…
Q2 INDUSTRY UPDATE
Petroleum Product Exports at an All-Time High
Even in the peak summer driving season with gasoline demand hitting all-time highs, U.S. refineries are still cranking out products. Gasoline stocks are up 10% from a year ago—15 million barrels (MMbbl) which is higher than the top of the five-year range—and just weeks ago, gasoline inventories made a contra-seasonal move upward, increasing by 1.4 MMbbl. Net exports for the first quarter were up almost five times over the same period in 2015.
Gasoline consumption this summer was projected to average 9.5 MMb/d, a solid 1.9% higher than the summer of 2015, which was a strong demand season itself. Even with high domestic demand for gasoline, net U.S. export volumes remain impressive.
Rocky Mountain Public Basket
The Rocky Mountain public basket is comprised of companies across all of our industry segments that are headquartered in the Mountain Region. Both quarterly and year to date stock price appreciation indicates growth activity that surpasses most individually segmented public baskets in Q2 2016…
The first quarter of 2016 saw a continuous mismatch between global oil supply and demand, which is depressing commodity prices and constraining industry profits. WTI crude prices dropped well below $30 in the first weeks of 2016 but made a partial recovery by the end of the quarter to just over $40 a barrel. Total domestic production finally has begun to drop and this trend is expected to continue in the coming year. Falling U.S. production, along with a tentative agreement on February 24 among Russia, Saudi Arabia, Venezuela and Qatar to cap production at January levels, prompted a 14% increase in bullish bets on West Texas Intermediate (WTI) futures, as some speculators predict supply tightening. However, the recent removal of sanctions on Iran’s oil industry means that Iranian oil likely will contribute to the supply glut as early as the second half of 2016.
Consistently low commodity prices have stifled industry profit margins, continuing the surge of cost-cutting that defined the industry in 2015. The low price environment will continue to push Oil & Gas companies to cut capital expenditures by an expected 30% in 2016, with over $200 billion worth of projects already postponed or canceled. An industry-wide escalation in debt loads in the last five years is now pressuring firms to maintain dividends through additional borrowing. Furthermore, major industry operators such as ExxonMobil and Chevron, which consistently have maintained or grown their dividends for the last 25 years, now are reporting quarterly losses for the first time since 2002. This has caused investors to expect a dividend cut.
As domestic consumers seek more energy-efficient transportation solutions such as alternatively fueled vehicles, public transportation and ride-sharing options, the industry has seen a decline in U.S. demand for finished petroleum products. This trend is predicted to continue throughout 2016 which, coupled with the simultaneous uptick in global energy requirements, will continue to increase U.S. refinery exports. With exports of refined products increasing by over 270% since 2005, midstream players are beginning to make substantial investments to expand their transportation infrastructure and processing capacity. Additionally, the recent lifting of a 40-year ban on unrefined oil exports should prompt more exports of U.S.-sourced crudes, which now account from merely 2% of domestic production.
Natural Gas is continuing to replace oil and coal in electricity generation because of the significant cost and environmental advantages. The Marcellus basin is one of the more prolific gas basins in the world, growing production from one billion cubic feet per day to about 16 billion cubic feet per day in the last five years. Actions taken by industrialized nations to reduce global warming resulted in Q1 of 2016 seeing a curtailment of fossil fuels usage, which additionally negatively impacted industry revenue.
Q4 was the most difficult quarter of 2015 for the Oil & Gas Industry, as global overproduction continued to depress commodity prices. WTI Crude fell below $38 a barrel for the first time since 2009, only to further drop below $30 in the first weeks of 2016. Although a decline in U.S. production began to have a small effect on global oversupply, an OPEC meeting held in early December established that the cartel would maintain its record-high output levels to preserve market share and support government subsidies. To combat the dropping price of oil, the industry has continued to explore additional cost eliminations within the system through more efficient methods of extraction, vertical industry cannibalization, supply chain optimization and personnel downsizing. By the end of Q4, this cost-cutting trend spread to dividend payouts, as demonstrated by the 75% decrease in the Kinder Morgan Inc. (NYSE:KMI) dividend on December 8.
Debt loads of North American-focused Exploration & Production (E&P) companies have quadrupled in the last 10 years (see Figure 1), proving some of these companies to be overleveraged. The historically aggressive financing of more profitable extraction techniques over the past decade indicates that 2016 could be the year of bankruptcies and redeterminations for E&P players. Refinery demand, however, has been steadily high, reflecting the quality and capacity of U.S. refineries and allowing these companies to capitalize on the year’s overproduction and arbitrage opportunities between raw and refined products.
An approximate 60% decrease of active rigs throughout 2015, teamed with a steady reduction in drilling permits granted on public lands since 2007, has left the domestic drilling industry at a standstill. Stabilization within the Oil & Gas industry is not expected until 2017, when demand is predicted to catch up with slowing production. The demand for oil will be notably driven by the industrialization of developing markets and economies. Recent U.S. deregulation surrounding exports will allow producers better access to these growing markets. Natural gas is also expected to start trending upward again in mid-2016, as Marcellus and Bakken shale gas continues to replace more expensive and environmentally harmful coal in electricity generation. Looking forward, appreciation in the trade-weighted index could harm domestic demand on the global market. With a strengthening U.S. dollar, exports will be relatively more expensive, potentially causing a world-wide demand shift towards sourcing oil and gas from outside of the U.S.
The Oil & Gas Industry has continued to struggle with the current low-price environment. The lower prices of Q1 and Q2 curtailed drilling operations and reduced rig counts within the US to less than half of what they were 12 months ago. However, in spite of the decreasing rig count, it has taken nine months for the market to see the inevitable declines in production. These declines have been accelerating as seen in RBN Energy’s US Shale Play Oil Production graph (see right). As a result, industry players have been looking to increase the efficiencies of current rigs, finding additional cash-generating strategies, or reducing current costs (which have come in the form of reduced payroll and exploration).
To avoid bankruptcy, many US-based producers have had no choice but to sell off their cheapened assets to those with stronger balance sheets. This has resulted in industry consolidation and increased levels of capital being invested into M&A transactions.
Due to the heightened demand for domestic refining services, Oil & Gas companies have turned to arbitrage opportunities within the pricing of domestic crude differentials. This trend toward efficiently pairing a new wave of “micro-crudes” with the refining services needed to get them to market has become more prominent as industry players work to reduce costs. Recent advances in drilling practices and other cost efficiencies have led analysts to speculate an industry-wide break-even point of about $45 to $60 per barrel for most North American producers, with major players attaining a break-even point as low as $25 per barrel. In this market environment, it is still cost effective to maintain many existing wells, but companies within the industry are continuing to be hesitant to begin new projects.
The Oil & Gas Industry has stabilized this quarter as the price of crude oil (WTI) rebounded from Q1 lows to a higher range of $52-$62 per barrel. OPEC reiterated in June that it would maintain output despite pleas to help prop up oil prices. In response, the oil companies in North America have decreased the number of active rigs by 50% from a year ago, as oil reserves have continued to build. Some U.S. producers have struggled to remain profitable with lower oil prices and reduced production, and have resorted to selling off assets in order to escape bankruptcy. This has presented an opportunity for companies with strong balance sheets to acquire additional assets and expand operations.
This buyer’s market has led to a 3.6% increase in the number of acquisitions compared to the first quarter of 2015. However, due to the limited number of companies that are financially capable to expand, the number of transactions is down 28.3% from the second quarter of 2014. In addition, sellers that can afford to hold out for higher oil & gas prices have done so in order to seek higher asset prices. Highlighting this trend, Williams Companies, Inc. (NYSE:WMB) rejected a buyout offer of $53.1 billion from Energy Transfer Equity, LP (NYSE:ETE) stating that the offer was inadequate for its shareholders. Williams Companies issued a statement saying that it has hired two advisory firms to evaluate potential strategic moves going forward, including the option of a sale.
Many pipeline operators have escaped the consequences of lower oil prices that have hurt the Equipment & Services segment. Imports of heavy crude from Venezuela, Mexico and Canada continue to increase as U.S. refining capacity remains available. Industry experts have hinted that the path to successful operations lies in increasing size while the price of oil remains lower. As a result, the industry may see additional takeover offers similar to Energy Transfer Equity’s in the second half of 2015.
The Oil & Gas Industry has again been at the forefront of headlines this quarter. The price of oil and natural gas has continued to fall with crude oil (WTI) trading for $45-$55 per barrel. OPEC has announced that it will not slow production to aid in the global stabilization of oil prices. Oil reserves are continuing to build, reaching record highs, contributing to the drop in price and dramatically impacting the industry. US producers are fighting to maintain profitability and are continuing to extract oil to maintain market share. Many companies have hedged against falling oil prices, locking in contracts for delivery at higher oil prices. However, the longer oil prices remain low, the benefit of hedging of future contracts diminishes. Oil and gas companies are beginning to feel the effects of these low prices on their bottom line and are revising investor guidance lower.
The number of completed transactions for the quarter is down 32% compared to 2014 Q1. Capital spending has also decreased during the first quarter of 2015. The threat of lower oil prices has caused companies to be conservative with their expansion activities into new markets until the volatility in oil prices subsides. Those companies that do have strong cash flow and a healthy balance sheet will find opportunities to grow value through strategic deals.
Development of new shale projects in the U.S. has provided many growth opportunities for oil and gas production. This has led U.S. dependence on foreign imports to diminish over the past years. Though foreign dependence has declined, domestic producers are still uncertain regarding future projects in part from the February presidential veto of the Keystone XL Pipeline.
After strong industry growth since the economic downturn, all sectors of the oil and gas industry witnessed major contraction in Q3 and Q4 2014. Crude oil prices continued to fall through the end of the year, dropping 42% within the past couple months and prompting IEA to make additional cuts to its 2015 demand forecasts. This drop in prices can be attributed to an abundant supply of oil and lower demand from Europe and Asia. In reaction to price decline, industry stock prices dropped from 10% growth in September 2014 to an average decline of almost 10% in December of 2014.
Innovative techniques, particularly hydraulic fracking and horizontal drilling, offered a silver lining of increased efficiency in production for the industry in 2014. However, with domestic oil production at its highest level in years and the government’s interest in reducing reliance on foreign oil, producers are scrambling to maintain levels of production despite the price drop. Stringent offshore drilling regulations in the Golf Coast have also offset industry growth in Q4 of 2014 and will continue to inhibit performance potential going into 2015.
Industry valuation multiples have remained somewhat stable despite the fall of oil prices and industry earnings. Revenue multiples remain equal to the S&P 500 average, showing investor confidence has remained steady despite the Q4 contraction. As Q4 2014 comes to a close, the oil and gas industry prepares for a 2015 market with excess supply and lowering demand but stable company values.
The S&P equal weight oil and gas index (S&P/TSX: GSPTE) showed steady growth since the start of 2014 and outperformed the S&P 500 index over Q2, reaching levels not seen since March of 2011. However, in Q3 the oil and gas index has been on a steady decline, dropping 64% from its peak in June. The dipping index could simply be the market correcting itself after initial reactions to June’s oil boom, which reached 8.5 million bpd. In addition, the index’s level shouldn’t overshadow that natural gas output for 2014 has been impressive with total gas withdrawals on pace to meet or exceed 2013’s all-time high level.
Even with the high levels of production, participants in the oil and gas industry face the challenge of keeping prices high enough to prevent revenue contraction. This challenge stems from production efficiencies that cause the supply of oil and gas to outstrip demand, ultimately pushing prices down. Nevertheless, if producers can manage to keep production levels at a high level without softening prices, the industry might be poised for another rally going into 2015.
Strong global demand and rising oil and gas prices continue to support industry revenue and facilitate strong M&A markets. The S&P equal weight oil and gas index (S&P/TSX: GSPTE) has shown steady growth since the start of the year, and has reached levels not seen since March of 2011. In the US, nearly half of crude oil production is coming from North Dakota and Texas according to the U.S. Energy Information Administration’s Petroleum Supply Monthly report. Production of crude oil in the U.S. reached 8.4 million barrels per day in April. The industry is poised to continue to benefit from the emergence of hydraulic fracturing and horizontal drilling techniques. These technological advances present further opportunity for the US to shift its dependence on foreign oil to oil production state side. With demand still high, the industry as a whole is expected to grow at approximately 2.4% annually until 2019.
Growth in the Oil & Gas industry generally comes through acquisition and 2014 has evidenced this as more transactions are expected to be consummated (on an annualized basis) than 2011, 2012 or 2013. This indicates a unique time for those in the industry to be a part of the booming transaction marketplace.
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